As filed with the Securities and Exchange
Commission on November 22, 2010

Registration
No. 333-169277

UNITED STATES SECURITIES AND
EXCHANGE COMMISSIONWashington, D.C.
20549

Amendment No. 5
to

Form S-1

REGISTRATION
STATEMENT

UNDER

THE SECURITIES ACT OF
1933

TARGA RESOURCES CORP.

(Exact name of registrant as
specified in its charter)

Delaware(State or other jurisdiction
of
incorporation or organization)

4922(Primary Standard
Industrial
Classification Code Number)

20-3701075(I.R.S. Employer
Identification Number)

1000 Louisiana, Suite 4300

Houston, Texas 77002

(713) 584-1000

(Address, including zip code,
and telephone number,

including area code, of
registrants principal executive offices)

Rene R. Joyce

Chief Executive Officer

1000 Louisiana, Suite 4300

Houston, Texas 77002

(713) 584-1000

(Name, address, including zip
code, and telephone number,

including area code, of agent
for service)

Copies to:

David P. Oelman

Douglass M. Rayburn

Christopher S. Collins

Baker Botts L.L.P.

Vinson & Elkins LLP

2001 Ross Avenue

1001 Fannin Street, Suite 2500

Dallas, Texas 75201

Houston, Texas 77002

(214) 953-6500

(713) 758-2222

Approximate date of commencement of proposed sale to the
public: As soon as practicable after this
Registration Statement becomes effective.

If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act, check the following
box. o

If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act,
please check the following box and list the Securities Act
registration statement number of the earlier effective
registration statement for the same
offering. o

If this Form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o

If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o

Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):

Large accelerated
filer o

Accelerated
filer o

Non-accelerated
filer þ

Smaller reporting
company o

(Do not check if a smaller
reporting company)

The Registrant hereby amends this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the registrant shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933 or until the Registration
Statement shall become effective on such date as the Securities
and Exchange Commission acting pursuant to said
Section 8(a), may determine.

The
information in this prospectus is not complete and may be
changed. We may not sell these securities until the registration
statement filed with the Securities and Exchange Commission is
effective. This prospectus is not an offer to sell these
securities and it is not soliciting offers to buy these
securities in any state where the offer or sale is not
permitted.

Subject to Completion, dated
November 22, 2010

PROSPECTUS

13,750,000 Shares

Targa Resources Corp.

Common Stock

This is the initial public offering of the common stock of Targa
Resources Corp. The selling stockholders identified in this
prospectus, including a member of our senior management, are
offering 13,750,000 shares of our common stock. We will not
receive any proceeds from the sale of shares by the selling
stockholders. No public market currently exists for our common
stock.

An affiliate of Merrill Lynch, Pierce, Fenner & Smith
Incorporated, an underwriter in this offering, is a selling
stockholder. See Underwriting (Conflicts of
Interest)Conflicts of Interest.

We have been approved to list our common stock on the New York
Stock Exchange under the symbol TRGP.

We anticipate that the initial public offering price will be
between $19.00 and $21.00 per share.

Investing in our common stock involves risks. See Risk
Factors beginning on page 23 of this prospectus.

Per Share

Total

Price to the public

$

$

Underwriting discounts and
commissions(1)

$

$

Proceeds to the selling stockholders

$

$

(1)

Excludes a structuring fee equal to 0.25% of the gross proceeds
of this offering, or approximately $687,500, payable by Targa
Resources Corp. to Barclays Capital Inc.

Certain of the selling stockholders have granted the
underwriters a
30-day
option to purchase up to an additional 2,062,500 shares of
common stock on the same terms and conditions as set forth above
if the underwriters sell more than 13,750,000 shares of
common stock in this offering.

Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or passed on the adequacy or accuracy of this
prospectus. Any representation to the contrary is a criminal
offense.

You should rely only on the information contained in this
prospectus. We have not, and the underwriters have not,
authorized anyone to provide you with different information. If
anyone provides you with different or inconsistent information,
you should not rely on it. We are not, and the underwriters are
not, making an offer to sell these securities in any
jurisdiction where an offer or sale is not permitted. You should
assume that the information appearing in this prospectus is
accurate as of the date on the front cover of this prospectus.
Our business, financial condition, results of operations and
prospects may have changed since that date.

Until ,
all dealers that buy, sell or trade our common stock, whether or
not participating in this offering, may be required to deliver a
prospectus. This requirement is in addition to the dealers
obligation to deliver a prospectus when acting as underwriters
and with respect to their unsold allotments or subscriptions.

This summary provides a brief overview of information
contained elsewhere in this prospectus. Because it is
abbreviated, this summary may not contain all of the information
that you should consider before investing in our common stock.
You should read the entire prospectus carefully, including the
historical financial statements and the notes to those financial
statements. Unless indicated otherwise, the information
presented in this prospectus assumes that the underwriters do
not exercise their option to purchase additional shares of our
common stock. You should read Risk Factors beginning
on page 23 for more information about important risks that
you should consider carefully before investing in our common
stock. We include a glossary of some of the terms used in this
prospectus as Appendix A.

As used in this prospectus, unless we indicate otherwise:
(1) our, we, us,
TRC, the Company and similar terms refer
either to Targa Resources Corp., formerly Targa Resources
Investments Inc., in its individual capacity or to Targa
Resources Corp. and its subsidiaries collectively, as the
context requires, (2) the General Partner
refers to Targa Resources GP LLC, the general partner of the
Partnership, and (3) the Partnership refers to
Targa Resources Partners LP in its individual capacity, to Targa
Resources Partners LP and its subsidiaries collectively, or to
Targa Resources Partners LP together with combined entities for
predecessor periods under common control, as the context
requires.

Targa Resources
Corp.

We own general and limited partner interests, including
incentive distribution rights (IDRs), in Targa
Resources Partners LP (NYSE: NGLS), a publicly traded Delaware
limited partnership that is a leading provider of midstream
natural gas and natural gas liquid services in the United
States. The Partnership is engaged in the business of gathering,
compressing, treating, processing and selling natural gas and
storing, fractionating, treating, transporting and selling
natural gas liquids, or NGLs, and NGL products. Our interests in
the Partnership consist of the following:



a 2% general partner interest, which we hold through our 100%
ownership interest in the general partner of the Partnership;



all of the outstanding IDRs of the Partnership; and



11,645,659 of the 75,545,409 outstanding common units of the
Partnership, representing a 15.1% limited partnership interest
in the Partnership.

Our primary business objective is to increase our cash available
for distribution to our stockholders by assisting the
Partnership in executing its business strategy. We may
facilitate the Partnerships growth through various forms
of financial support, including, but not limited to, modifying
the Partnerships IDRs, exercising the Partnerships
IDR reset provision contained in its partnership agreement,
making loans, making capital contributions in exchange for
yielding or non-yielding equity interests or providing other
financial support to the Partnership, if needed, to support its
ability to make distributions. In addition, we may acquire
assets that could be candidates for acquisition by the
Partnership, potentially after operational or commercial
improvement or further development.

Our cash flows are generated from the cash distributions we
receive from the Partnership. The Partnership is required to
distribute all available cash at the end of each quarter after
establishing reserves to provide for the proper conduct of its
business or to provide for future distributions. Our ownership
of the Partnerships IDRs and general partner interests
entitle us to receive:



2% of all cash distributed in a quarter until $0.3881 has been
distributed in respect of each common unit of the Partnership
for that quarter;



15% of all cash distributed in a quarter after $0.3881 has been
distributed in respect of each common unit of the Partnership
for that quarter;



25% of all cash distributed in a quarter after $0.4219 has been
distributed in respect of each common unit of the Partnership
for that quarter; and

50% of all cash distributed in a quarter after $0.50625 has been
distributed in respect of each common unit of the Partnership
for that quarter.

On November 4, 2010, the Partnership announced that
management plans to recommend to the General Partners
board of directors a $0.04 increase in the annualized cash
distribution rate to $2.19 per common unit for the fourth
quarter of 2010 distribution. Based on a $2.19 annualized rate,
a quarterly distribution by the Partnership of $0.5475 per
common unit will result in a quarterly distribution to us of
$6.4 million, or $25.5 million on an annualized basis,
in respect of our common units in the Partnership. Such
distribution would also result in a quarterly distribution to us
of $6.3 million, or $25.2 million on an annualized
basis, in respect of our 2% general partner interest and IDRs
for total quarterly distributions of $12.7 million, or
$50.7 million on an annualized basis.

We intend to pay to our stockholders, on a quarterly basis,
dividends equal to the cash the Partnership distributes to us
based on our ownership of Partnership securities, less the
expenses of being a public company, other general and
administrative expenses, federal income taxes, capital
contributions to the Partnership and reserves established by our
board of directors. Based on the current distribution policy of
the Partnership, we plan to pay an initial quarterly dividend of
$0.2575 per share of our common stock, or $1.03 per
share on an annualized basis, for a total quarterly dividend of
approximately $10.9 million, or $43.6 million on an
annualized basis, per our dividend policy, which we will adopt
prior to the conclusion of this offering. See Our Dividend
Policy.

The following graph shows the historical cash distributions
declared by the Partnership for the periods shown to its limited
partners (including us), to us based on our 2% general partner
interest in the Partnership and to us based on the IDRs. The
increases in historical cash distributions to both the limited
partners and the general partner since the second quarter ended
June 30, 2007, as reflected in the graph set forth below,
generally resulted from increases in the Partnerships per
unit quarterly distribution over time and the issuance of
approximately 44.7 million additional common units by the
Partnership over time to finance acquisitions and capital
improvements. Over the same period, the quarterly distributions
declared and to be recommended by the Partnership in respect of
our 2% general partner interest and IDRs increased approximately
3,050% from $0.2 million to $6.3 million.

The graph set forth below shows hypothetical cash distributions
payable to us in respect of our interests in the Partnership
across an illustrative range of annualized distributions per
common unit. This information is based upon the following:



the Partnership has a total of 75,545,409 common units
outstanding; and



we own (i) a 2% general partner interest in the
Partnership, (ii) the IDRs and (iii) 11,645,659 common
units of the Partnership.

The graph below also illustrates the impact on us of the
Partnership raising or lowering its per common unit distribution
from the fourth quarter quarterly distribution of $0.5475 per
common unit, or $2.19 per common unit on an annualized basis,
that management plans to recommend to the General Partners
board of directors. This information is presented for
illustrative purposes only; it is not intended to be a
prediction of future performance and does not attempt to
illustrate the impact that changes in our or the
Partnerships business, including changes that may result
from changes in interest rates, energy prices or general
economic conditions, or the impact that any future acquisitions
or expansion projects, divestitures or the issuance of
additional debt or equity securities, will have on our or the
Partnerships results of operations.

Hypothetical
Annualized Pre-Tax Partnership Distributions to
Us(1)

(1)

For the fourth quarter of 2010,
management plans to recommend a quarterly cash distribution of
$0.5475 per common unit, or $2.19 per common unit on an
annualized basis.

The impact on us of changes in the Partnerships
distribution levels will vary depending on several factors,
including the Partnerships total outstanding partnership
interests on the record date for the distribution, the aggregate
cash distributions made by the Partnership and the interests in
the Partnership owned by us. If the Partnership increases
distributions to its unitholders, including us, we would expect
to increase dividends to our stockholders, although the timing
and amount of such increased dividends, if any, will not
necessarily be comparable to the timing and amount of the
increase in distributions made by the Partnership. In addition,
the level of distributions we receive and of dividends we pay to
our stockholders may be affected by the various risks associated
with an investment in us and the underlying business of the
Partnership. Please read Risk Factors for more
information about the risks that may impact your investment
in us.

Targa Resources
Partners LP

The Partnership is a leading provider of midstream natural gas
and NGL services in the United States and is engaged in the
business of gathering, compressing, treating, processing and
selling natural gas and storing, fractionating, treating,
transporting and selling NGLs and NGL products. The Partnership
operates in two primary divisions: (i) Natural Gas
Gathering and Processing, consisting of two
segments(a) Field Gathering and Processing and
(b) Coastal Gathering and Processing; and (ii) NGL
Logistics and Marketing, consisting of two
segments(a) Logistics Assets and (b) Marketing
and Distribution.

The Partnership currently owns interests in or operates
approximately 11,372 miles of natural gas pipelines and
approximately 800 miles of NGL pipelines, with natural gas
gathering systems covering approximately 13,500 square
miles and 22 natural gas processing plants with access to
natural gas supplies in the Permian Basin, the Fort Worth
Basin, the onshore region of the Louisiana Gulf Coast and the
Gulf of Mexico.

Additionally, the Partnerships integrated NGL logistics
and marketing division, or Downstream Business, has
net NGL fractionation capacity of approximately 314 MBbl/d,
48 owned and operated storage wells with a net storage capacity
of approximately 67 MMBbl, and 15 storage, marine and
transport terminals with above ground NGL storage capacity of
approximately 825 MBbl.

Since the beginning of 2007, the Partnership has completed six
acquisitions from us with an aggregate purchase price of
approximately $3.1 billion. In addition, and over the same
period, the Partnership has invested approximately
$196 million in growth capital expenditures. We believe
that the Partnership is well positioned to continue the
successful execution of its business strategies, including
accretive acquisitions and expansion projects, and that the
Partnerships inventory of growth projects should help to
sustain continued growth in cash distributions paid by the
Partnership.

Based on the Partnerships closing common unit price on
November 15, 2010, the Partnership has an equity market
capitalization of $2.3 billion. As of September 30,
2010, the Partnership had total assets of $3.1 billion.

Recent
Transactions

On August 25, 2010, the Partnership acquired from us a 63%
ownership interest in Versado Gas Processors, L.L.C.
(Versado), a joint venture in which Chevron U.S.A.
Inc. owns the remaining 37% interest, for a purchase price of
$247.2 million. Versado owns a natural gas gathering and
processing business consisting of the Eunice, Monument and
Saunders gathering and processing systems, including treating
operations, processing plants and related assets (collectively,
the Versado System). The Versado System includes
three refrigerated cryogenic processing plants and approximately
3,200 miles of combined gathering pipelines in Southeast
New Mexico and West Texas and is primarily conducted under
percent of proceeds arrangements. During 2009, the Versado
System processed an average of approximately
198.8 MMcf/d
of natural gas and produced an average of approximately
22.2 MBbl/d of NGLs. In the first nine months of 2010, the
Versado System processed an average of approximately
180.5 MMcf/d
of natural gas and produced an average of approximately
20.4 MBbl/d of NGLs.

On September 28, 2010, the Partnership acquired from us a
77% ownership interest in Venice Energy Services Company, L.L.C.
(VESCO), a joint venture in which Enterprise Gas
Processing, LLC and Oneok Vesco Holdings, L.L.C. own the
remaining ownership interests, for a purchase price of
$175.6 million. VESCO owns and operates a natural gas
gathering and processing business in Louisiana consisting of a
coastal straddle plant and the business and operations of Venice
Gathering System, L.L.C., a wholly owned subsidiary of VESCO
that owns and operates an offshore gathering system and related
assets (collectively, the VESCO System). The VESCO
System captures volumes from the Gulf of Mexico shelf and
deepwater. For the year ended December 31, 2009 and for the
nine months ended September 30, 2010, VESCO processed
363 MMcf/d
and
423 MMcf/d
of natural gas, respectively.

On October 8, 2010, the Partnership declared a quarterly
cash distribution of $0.5375 per common unit, or $2.15 per
common unit on an annualized basis for the third quarter of
2010, payable on November 12, 2010 to holders of record on
October 18, 2010.

On November 4, 2010, the Partnership announced that
management plans to recommend to the General Partners
board of directors a $0.04 increase in the annualized cash
distribution rate to $2.19 per common unit for the fourth
quarter of 2010 distribution.

We believe the Partnerships near-term growth will be
driven both by significant recently completed or pending
projects as well as strong supply and demand fundamentals for
its existing businesses. Over the longer-term, we expect the
Partnerships growth will be driven by natural gas shale
opportunities, which could lead to growth in both the
Partnerships Gathering and Processing division and
Downstream Business, organic growth projects and potential
strategic and other acquisitions related to its existing
businesses.

Organic growth projects. We expect the
Partnerships near-term growth to be driven by a number of
significant projects scheduled for completion in 2011 and 2012
that are supported by long-term, fee-based contracts. These
projects include:

Benzene treating project: A new treater is
under construction which will operate in conjunction with the
Partnerships existing low sulfur natural gasoline
(LSNG) facility at Mont Belvieu and is designed to
reduce benzene content of natural gasoline to meet new, more
stringent environmental standards. The treater has an estimated
gross cost of approximately $33 million.



Gulf Coast Fractionators expansion
project: The Partnership has announced plans by
Gulf Coast Fractionators (GCF), a partnership with
ConocoPhillips and Devon Energy Corporation in which the
Partnership owns a 38.8% interest, to expand the capacity of its
NGL fractionation facility in Mont Belvieu by 43 MBbl/d for
an estimated gross cost of $75 million.



SAOU Expansion Program: The Partnership has
announced a $30 million capital expenditure program
including new compression facilities and pipelines as well as
expenditures to restart the
25 MMcf/d
Conger processing plant in response to strong volume growth and
new well connects.

The Partnership has successfully completed both large and small
organic growth projects that are associated with its existing
assets and expects to continue to do so in the future. These
projects have involved growth capital expenditures of
approximately $245 million since 2005 and include an LSNG
project, operations improvements and efficiency enhancements,
opportunistic commercial development activities, and other
enhancements.

Strong supply and demand fundamentals for the
Partnerships existing businesses. We
believe that the current strength of oil, condensate and NGL
prices and of forecast prices for these energy commodities has
caused producers in and around the Partnerships natural
gas gathering and processing areas of operation to focus their
drilling programs on regions rich in these forms of
hydrocarbons. Liquids rich gas is prevalent from the Wolfberry
Trend and Canyon Sands plays, which are accessible by the SAOU
processing business in the Permian Basin (known as
SAOU), the Wolfberry and Bone Springs plays, which
are accessible by the Sand Hills system, and from
oilier portions of the Barnett Shale natural gas
play, especially portions of Montague, Cooke, Clay and Wise
counties, which are accessible by the North Texas System.

Producer activity in areas rich in oil, condensate and NGLs is
currently generating high demand for the Partnerships
fractionation services at the Mont Belvieu market hub. As a
result, fractionation volumes have recently increased to near
existing capacity. Until additional fractionation capacity comes
on-line in 2011, there will be limited incremental supply of
fractionation services in the area. These strong supply and
demand fundamentals have resulted in long-term,
take-or-pay
contracts for existing capacity and support the construction of
new fractionation capacity, such as the Partnerships CBF
and GCF expansion projects. The Partnership is continuing to see
rates for fractionation services increase. The

higher volumes of fractionated NGLs should also result in
increased demand for other related fee-based services provided
by the Partnerships Downstream Business.

Natural gas shale opportunities. The
Partnership is actively pursuing natural gas gathering and
processing and NGL fractionation opportunities associated with
many of the active, liquids rich natural gas shale plays, such
as certain regions of the Marcellus Shale and Eagle Ford Shale.
We believe that the Partnerships leadership position in
the NGL Logistics and Marketing business, which includes the
Partnerships fractionation services, provides the
Partnership with a competitive advantage relative to other
gathering and processing companies without these capabilities.

Potential third party acquisitions related to the
Partnerships existing businesses. While the
Partnerships recent growth has been partially driven by
the implementation of a focused drop drown strategy, our
management team also has a record of successful third party
acquisitions. Since our formation, our strategy has included
approximately $3 billion in acquisitions and growth capital
expenditures.

Our management team will continue to manage the
Partnerships business after this offering, and we expect
that third-party acquisitions will continue to be a significant
focus of the Partnerships growth strategy.

The
Partnerships Competitive Strengths and
Strategies

We believe the Partnership is well positioned to execute its
business strategy due to the following competitive strengths:



The Partnership is one of the largest fractionators of NGLs in
the Gulf Coast region.



The Partnerships gathering and processing businesses are
predominantly located in active and growth oriented oil and gas
producing basins.



The Partnership provides a comprehensive package of services to
natural gas producers.

The Partnership maintains gathering and processing positions in
strategic oil and gas producing areas across multiple basins and
provides services under attractive contract terms to a diverse
mix of customers.



Maintaining appropriate leverage and distribution coverage
levels and mitigating commodity price volatility allow the
Partnership to be flexible in its growth strategy and enable it
to pursue strategic acquisitions and large growth projects.



The executive management team which formed TRI Resources Inc.,
formerly Targa Resources, Inc., in 2004 and continues to manage
Targa today possesses over 200 years of combined experience
working in the midstream natural gas and energy business.

The
Partnerships Challenges

The Partnership faces a number of challenges in implementing its
business strategy. For example:



The Partnership has a substantial amount of indebtedness which
may adversely affect its financial position.



The Partnerships cash flow is affected by supply and
demand for oil, natural gas and NGL products and by natural gas
and NGL prices, and decreases in these prices could adversely
affect its results of operations and financial condition.

The Partnerships long-term success depends on its ability
to obtain new sources of supplies of natural gas and NGLs, which
depends on certain factors beyond its control. Any decrease in
supplies of natural gas or NGLs could adversely affect the
Partnerships business and operating results.



If the Partnership does not make acquisitions or investments in
new assets on economically acceptable terms or efficiently and
effectively integrate new assets, its results of operations and
financial condition could be adversely affected.



The Partnership is subject to regulatory, environmental,
political, legal and economic risks, which could adversely
affect its results of operations and financial condition.



The Partnerships growth strategy requires access to new
capital. Tightened capital markets or increased competition for
investment opportunities could impair its ability to grow.



The Partnerships hedging activities may not be effective
in reducing the variability of its cash flows and may, in
certain circumstances, increase the variability of its cash
flows.



The Partnerships industry is highly competitive, and
increased competitive pressure could adversely affect the
Partnerships business and operating results.

For a further discussion of these and other challenges we face,
please read Risk Factors.

We were formed in October 2005 as a Delaware corporation to
become the top-tier holding company for TRI Resources Inc.,
formerly Targa Resources, Inc. We currently have outstanding a
total of (i) 6,409,697 shares of Series B
Convertible Participating Preferred Stock par value
$0.001 per share (Series B Preferred) held
by affiliates of Warburg Pincus LLC (Warburg
Pincus), an affiliate of Bank of America and members of
management and (ii) 10,228,520 shares of common stock
held by members of management and other employees.

All shares of our outstanding Series B Preferred were issued in
connection with our formation in October 2005 either by way of
purchase or exchange. All shares of our outstanding common stock
were issued under our 2005 Stock Incentive Plan as a direct
issuance, as a result of option exercises or in exchange for
Series B Preferred options.

Following effectiveness of the registration statement of which
this prospectus forms a part, (1) we will effect a
1 for 2.05 reverse split of our common stock to reduce
the number of shares of our common stock that are currently
outstanding and (2) all of our shares of Series B
Preferred will automatically convert into shares of common
stock, based on (a) the 10 to 1 conversion ratio applicable
to the Series B Preferred plus (b) the accreted value
per share (which includes accrued and unpaid dividends) of the
Series B Preferred divided by the initial public offering
price for this offering after deducting underwriting discounts
and commissions, in each case after giving effect to the reverse
split. We also expect to issue equity awards that total
approximately 1.9 million shares of common stock in
connection with the offering under a new stock incentive plan.
Please see Management  Executive
Compensation  Compensation Discussion and
Analysis  Changes in Connection with the Completion
of this Offering for a description of the new stock
incentive plan and the proposed initial grant under the plan.

As described above, the number of shares of common stock to be
issued upon conversion of our preferred stock will depend on the
initial public offering price as well as the accreted value of
the preferred stock. For purposes of this preliminary
prospectus, we have presented all common stock ownership amounts
and percentages based on an assumed initial public offering
price of $20.00 per share, which is the midpoint of the range of
prices shown on the cover of this preliminary prospectus as of
the date hereof and an accreted value of the Series B
Preferred of $80 million.

The following chart depicts our organizational and ownership
structure after giving effect to this offering and the
transactions described above. Upon completion of this offering,
there will be a total of 42,292,381 common shares outstanding,
consisting of the following:



Affiliates of Warburg Pincus will own 18,604,233 shares of
common stock, representing a 44.0% ownership interest in us.



An affiliate of Bank of America will own 1,652,159 shares
of common stock representing a 3.9% ownership interest
in us.



Our employees, including our executive officers, will own
approximately 8.3 million shares of common stock,
representing a 19.6% ownership interest in us, including
the approximately 1.9 million shares of common stock we
expect to issue under the new stock incentive plan to be adopted
in conjunction with this offering.



Our public stockholders will own 13,750,000 shares of
common stock, representing a 32.5% ownership interest in us.



We will indirectly own 100% of the ownership interest in the
General Partner, which will own the 2% general partner interest
in the Partnership and all of the Partnerships IDRs.



We will indirectly own 11,645,659 of the Partnerships
75,545,409 outstanding common units, representing a 15.1%
limited partner interest in the Partnership.

Gives effect to our corporate reorganization as described above
under  Our Structure and Ownership After This
Offering, the sale of common stock offered by the selling
stockholders in this offering, and awards of common stock that
will be granted to the directors and executive officers upon the
closing of this offering.

Certain of the selling stockholders have granted the
underwriters a
30-day
option to purchase up to an aggregate of
2,062,500 additional shares of our common stock to cover
over-allotments.

Use of proceeds

We will not receive any proceeds from this offering.

Dividend policy

We intend to pay to our stockholders, on a quarterly basis,
dividends equal to the cash we receive from our Partnership
distributions, less reserves for expenses, future dividends and
other uses of cash, including:

 federal income taxes, which we are required to pay
because we are taxed as a corporation;

 the expenses of being a public company;

 other general and administrative expenses;

 reserves our board of directors believes prudent to
maintain; and

 capital contributions to the Partnership upon the
issuance by it of additional partnership securities if we choose
to maintain the General Partners 2% interest.

Dividends

Based on the current distribution policy of the Partnership, our
expected federal income tax liabilities, our expected level of
other expenses and reserves, we expect that our initial
quarterly dividend rate will be $0.2575 per share. We expect to
pay a prorated dividend for the portion of the fourth quarter of
2010 that we are public in February 2011.

However, we cannot assure you that any dividends will be
declared or paid by us. Based on the distributions paid by the
Partnership to its unitholders for each of the immediately
preceding four quarters, we believe we would have been able to
pay the initial quarterly dividend to our shareholders for each
of the immediately preceding four quarters. We expect that we
will be able to pay the initial quarterly dividend for the three
months ending December 31, 2010 and each of the four
quarters in the year ending December 31, 2011. Please read
Our Dividend Policy.

Tax

For a discussion of the material tax consequences that may be
relevant to prospective stockholders who are
non-U.S.
holders

You should carefully read and consider the information beginning
on page 23 of this prospectus set forth under the heading
Risk Factors and all other information set forth in
this prospectus before deciding to invest in our common stock.

New York Stock Exchange symbol

TRGP

Conflicts of interest

An affiliate of Merrill Lynch, Pierce, Fenner & Smith
Incorporated, an underwriter in this offering, is selling
1,110,280 shares of common stock in connection with this
offing and will own 1,652,159 shares of our common stock,
representing a 3.9% ownership interest in us on a fully diluted
basis upon completion of this offering. Because of this
relationship, this offering is being conducted in accordance
with Rule 2720 of the NASD Conduct Rules (which are part of
the FINRA Rules). This rule requires, among other things, that a
qualified independent underwriter has participated in the
preparation of, and has exercised the usual standards of due
diligence with respect to, this prospectus and the registration
statement of which this prospectus is a part. Barclays Capital
Inc. is acting as the qualified independent underwriter. See
Underwriting (Conflicts of Interest)Conflicts of
Interest.

(1)

This number gives effect to the assumed common stock split, to
conversion of our outstanding preferred stock into shares of our
common stock and to the expected issuance of shares of common
stock under our new stock incentive plan, all of which are
described under  Our Structure and Ownership
After This Offering.

Comparison of
Rights of Our Common Stock and the Partnerships Common
Units

Our shares of common stock and the Partnerships common
units are unlikely to trade, either by volume or price, in
correlation or proportion to one another. Instead, while the
trading prices of our shares and the common units may follow
generally similar broad trends, the trading prices may diverge
because, among other things:



common unitholders of the Partnership have a priority over the
IDRs with respect to the Partnership distributions;



we participate in the General Partners distributions and
IDRs and the common unitholders do not;



we and our stockholders are taxed differently from the
Partnership and its common unitholders; and



we may enter into other businesses separate and apart from the
Partnership or any of its affiliates.

An investment in common units of a partnership is inherently
different from an investment in common stock of a corporation.

Partnerships Common Units

Our Shares

Distributions and Dividends

The Partnership pays its limited partners and the General Partner quarterly distributions equal to all of the available cash from operating surplus. The General Partner has a 2% general partner interest.

Common unitholders do not participate in the distributions to the General Partner or in the IDRs.

We intend to pay our stockholders, on a quarterly basis,
dividends equal to the cash the Partnership distributes to us
based on our ownership of Partnership interests, less federal
income taxes, which we are required to pay because we are taxed
as a corporation, the expenses of being a public company, other
general and administrative expenses, capital contributions to
the Partnership upon the issuance by it of additional
Partnership securities if we choose to maintain the General
Partners 2% interest and reserves established by our board
of directors.

We receive distributions from the Partnership with respect to
our 11,645,659 common units.

In addition, through our ownership of the Partnerships
general partner, we participate in the distributions to the
General Partner pursuant to the 2% general partner interest and
the IDRs. If the Partnership is successful in implementing its
strategy to increase distributable cash flow, our income from
these rights may increase in the future. However, no
distributions may be made on the IDRs until the minimum
quarterly distribution has been paid on all outstanding common
units. Therefore, distributions with respect to the IDRs are
even more uncertain than distributions on the common units.

Taxation of Entity and Equity Owners

The Partnership is a flow-through entity that is not subject to an entity level federal income tax.

The Partnership expects that holders of units in the Partnership other than us will benefit for a period of time from tax basis adjustments and remedial allocations of deductions so that they will be allocated a relatively small amount of federal taxable income compared to the cash distributed to them.

Our taxable income is subject to U.S. federal income tax at the
corporate tax rate, which is currently a maximum of 35%. In
addition, we will be allocated more taxable income relative to
our Partnership distributions than the other common unitholders
and the relative amount thereof may increase if the Partnership
issues additional units or distributes a higher percentage of
cash to the holder of the IDRs.

Common unitholders will receive Forms K-1 from the Partnership reflecting the unitholders share of the Partnerships items of income, gain, loss, and deduction.

Tax-exempt organizations, including employee benefit plans, will have unrelated business taxable income as a result of the allocation of the Partnerships items of income, gain, loss, and deduction to them.

Regulated investment companies or mutual funds will be allocated items of income, which will not constitute qualifying income, as a result of the ownership of common units.

Because we are not a flow-through entity, our stockholders do not report our items of income, gain, loss and deduction on their federal income tax returns. Distributions to our stockholders will constitute dividends for U.S. tax purposes to the extent of our current or accumulated earnings and profits. To the extent those distributions are not treated as dividends, they will be treated as gain from the sale of the common stock to the extent the distribution exceeds a stockholders adjusted basis in the common stock sold.

Our stockholders will generally recognize capital gain or loss on the sale of our common stock equal to the difference between a stockholders adjusted tax basis in the shares of common stock sold and the proceeds received by such holder. This gain or loss will generally be long-term gain or loss if a holder sells shares of common stock held for more than one year. Under current law, long-term capital gains of individuals generally are subject to a reduced rate of U.S. federal income tax.

Tax-exempt organizations, including employee benefit plans, will not have unrelated business taxable income upon the receipt of dividends from us. Regulated investment companies or mutual funds will have qualifying income as a result of dividends received from us.

Certain significant decisions require approval by a unit
majority of the common units. These significant decisions
include, among other things:

 merger of the Partnership or the sale of
all or substantially all of its assets in certain circumstances;
and

 certain amendments to the
Partnerships partnership agreement.

For more information, please read Material Provisions of
the Partnerships Partnership AgreementVoting
Rights.

Under our amended and restated bylaws, each stockholder will be
entitled to cast one vote, either in person or by proxy, for
each share standing in his or her name on the books of the
corporation as of the record date. Our amended and restated
certificate of incorporation and amended and restated bylaws
will contain supermajority voting requirements for certain
matters. See Description of Our Capital
StockAnti-Takeover Effects of Provisions of Our Amended
and Restated Certificate of Incorporation, Our Amended and
Restated Bylaws and Delaware LawCertificate of
Incorporation and Bylaws.

Election, Appointment and Removal of General Partner and
Directors

Common unitholders do not elect the directors of Targa Resources GP LLC. Instead, these directors are elected annually by us, as the sole equity owner of Targa Resources GP LLC.

The Partnerships general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of the outstanding units, voting together as a single class, including units held by the general partner and its affiliates, and the Partnership receives an opinion of counsel regarding limited liability and tax matters.

Under our amended and restated bylaws, we will have a staggered board of three classes with each class being elected every three years and only one class elected each year. Also, each director shall hold office until the directors successor shall have been duly elected and shall qualify or until the director shall resign or shall have been removed.

Directors serving on our board may only be removed from office for cause and only by the affirmative vote of a supermajority of our stockholders. See Description of Our Capital StockAnti-Takeover Effects of Provisions of our Amended and Restated Certificate of Incorporation, our Amended and Restated Bylaws and Delaware LawCertificate of Incorporation and Bylaws.

Whenever the Partnership issues equity securities to any person
other than the General Partner and its affiliates, the General
Partner has a preemptive right to purchase additional limited
partnership interests on the same terms in order to maintain its
percentage interest.

Liquidation

The Partnership will dissolve upon any of the following:

We will dissolve upon any of the following:

 the election of the general partner to
dissolve the Partnership, if approved by the holders of units
representing a unit majority;

 there being no limited partners, unless
the Partnership is continued without dissolution in accordance
with applicable Delaware law;

 the entry of a decree of judicial
dissolution of us; or

 the approval of at least 67% of our
outstanding common stock.

 the entry of a decree of judicial
dissolution of the Partnership pursuant to applicable Delaware
law; or

 the withdrawal or removal of the General
Partner or any other event that results in its ceasing to be the
general partner other than by reason of a transfer of its
general partner interest in accordance with the
Partnerships partnership agreement or withdrawal or
removal following approval and admission of a successor.

Our principal executive offices are located at 1000 Louisiana,
Suite 4300, Houston, Texas 77002 and our telephone number
is
(713) 584-1000.
Our website is located at www.targaresources.com. We will make
our periodic reports and other information filed with or
furnished to the Securities and Exchange Commission, or the SEC,
available, free of charge, through our website, as soon as
reasonably practicable after those reports and other information
are electronically filed with or furnished to the SEC.
Information on our website or any other website is not
incorporated by reference into this prospectus and does not
constitute a part of this prospectus.

The following table presents selected historical consolidated
financial and operating data of Targa Resources Corp. for the
periods and as of the dates indicated. The summary historical
consolidated statement of operations and cash flow data for the
years ended December 31, 2007, 2008 and 2009 and summary
historical consolidated balance sheet data as of
December 31, 2008 and 2009 have been derived from our
audited financial statements, included elsewhere in this
prospectus. The summary historical consolidated statement of
operations and cash flow data for the nine months ended
September 30, 2009 and 2010 and the summary historical
consolidated balance sheet data as of September 30, 2010
have been derived from our unaudited financial statements,
included elsewhere in this prospectus. The summary historical
consolidated balance sheet data as of December 31, 2007 has
been derived from our audited financial statements and the
summary historical consolidated balance sheet as of
September 30, 2009 has been derived from our unaudited
financial statements, neither of which is included in this
prospectus.

Our summary unaudited pro forma condensed consolidated statement
of operations data and unaudited pro forma balance sheet data
give effect to this offering and to the following events that
have occurred subsequent to September 30, 2010:



the agreed repurchase on November 5, 2010 from certain
holders of our Holdco Loan of $141.3 million of face value
debt for $137.4 million;



the expected award by the Company of approximately
1.9 million shares of common stock under the new stock
incentive plan that we expect to adopt in connection with this
offering; and



the $18.0 million cash dividend on the Series B
preferred stock that was declared by the TRC board of directors
on November 19, 2010 and will be paid on November 22,
2010. The cash dividend represents a portion of the accreted
value of the Series B preferred stock included in our
September 30, 2010 balance sheet.

The unaudited pro forma condensed consolidated financial
information has been prepared by applying pro forma adjustments
to the historical financial statements of Targa Resources Corp.
The pro forma adjustments have been prepared as if the pro forma
transactions had taken place on September 30, 2010, in the
case of the unaudited pro forma condensed consolidated balance
sheet, or as of January 1, 2009, in the case of the
unaudited pro forma condensed consolidated statement of
operations.

We derived the information in the following table from, and that
information should be read together with and is qualified in its
entirety by reference to, the historical combined and unaudited
pro forma condensed consolidated financial statements and the
accompanying notes included elsewhere in this prospectus.

Includes business interruption
insurance revenues of $3.0 million and $7.9 million
for the nine months ended September 30, 2010 and 2009 and
$21.5 million, $32.9 million and $7.3 million for
the years ended December 31, 2009, 2008, and 2007.

(2)

Based on the terms of the preferred
convertible stock, undistributed earnings of the Company are
allocated to the preferred stock until the carrying value has
been recovered.

(3)

Gross margin is a non-GAAP
financial measure and is discussed under Managements
Discussion and Analysis of Financial Condition and Results of
OperationsHow We Evaluate Our Operations.

(4)

Operating margin is a non-GAAP
financial measure and is discussed under Managements
Discussion and Analysis of Financial Condition and Results of
OperationsHow We Evaluate Our Operations.

(5)

Plant natural gas inlet represents
the volume of natural gas passing through the meter located at
the inlet of a natural gas processing plant.

The nature of our business activities subjects us to certain
hazards and risks. You should carefully consider the risks
described below, in addition to the other information contained
in this prospectus, before making an investment decision.
Realization of any of these risks or events could have a
material adverse effect on our business, financial condition,
cash flows and results of operations, which could result in a
decline in the trading price of our common stock, and you may
lose all or part of your investment.

Risks Inherent in
an Investment in Us

Our cash flow
is dependent upon the ability of the Partnership to make cash
distributions to us.

Our cash flow consists of cash distributions from the
Partnership. The amount of cash that the Partnership will be
able to distribute to its partners, including us, each quarter
principally depends upon the amount of cash it generates from
its business. For a description of certain factors that can
cause fluctuations in the amount of cash that the Partnership
generates from its business, please read Risks
Inherent in the Partnerships Business and
Managements Discussion and Analysis of Financial
Condition and Results of OperationsFactors That
Significantly Affect Our Results. The Partnership may not
have sufficient available cash each quarter to continue paying
distributions at their current level or at all. If the
Partnership reduces its per unit distribution, because of
reduced operating cash flow, higher expenses, capital
requirements or otherwise, we will have less cash available for
distribution to you and would probably be required to reduce the
dividend per share of common stock paid to you. You should also
be aware that the amount of cash the Partnership has available
for distribution depends primarily upon the Partnerships
cash flow, including cash flow from the release of reserves as
well as borrowings, and is not solely a function of
profitability, which will be affected by non-cash items. As a
result, the Partnership may make cash distributions during
periods when it records losses and may not make cash
distributions during periods when it records profits.

Once we receive cash from the Partnership and the General
Partner, our ability to distribute the cash received to our
stockholders is limited by a number of factors, including:



our obligation to (i) satisfy tax obligations associated
with previous sales of assets to the Partnership,
(ii) reimburse the Partnership for certain capital
expenditures related to Versado and (iii) provide the
Partnership with limited quarterly distribution support through
2011, all as described in more detail in Managements
Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital Resources;



interest expense and principal payments on any indebtedness we
incur;



restrictions on distributions contained in any existing or
future debt agreements;



our general and administrative expenses, including expenses we
will incur as a result of being a public company as well as
other operating expenses;



expenses of the General Partner;



income taxes;



reserves we establish in order for us to maintain our 2% general
partner interest in the Partnership upon the issuance of
additional partnership securities by the Partnership; and



reserves our board of directors establishes for the proper
conduct of our business, to comply with applicable law or any
agreement binding on us or our subsidiaries or to provide for
future dividends by us.

For additional information, please read Our Dividend
Policy. In the future, we may not be able to pay dividends
at or above our estimated initial quarterly dividend of $0.2575
per share, or $1.03 per share on an

annualized basis. The actual amount of cash that is available
for dividends to our stockholders will depend on numerous
factors, many of which are beyond our control.

A reduction in
the Partnerships distributions will disproportionately
affect the amount of cash distributions to which we are
entitled.

Our ownership of the IDRs in the Partnership entitles us to
receive specified percentages of the amount of cash
distributions made by the Partnership to its limited partners
only in the event that the Partnership distributes more than
$0.3881 per unit for such quarter. As a result, the holders of
the Partnerships common units have a priority over our
IDRs to the extent of cash distributions by the Partnership up
to and including $0.3881 per unit for any quarter.

Our IDRs entitle us to receive increasing percentages, up to
48%, of all cash distributed by the Partnership. Because the
Partnerships distribution rate is currently above the
maximum target cash distribution level on the IDRs, future
growth in distributions we receive from the Partnership will not
result from an increase in the target cash distribution level
associated with the IDRs. Furthermore, a decrease in the amount
of distributions by the Partnership to less than $0.50625 per
unit per quarter would reduce the General Partners
percentage of the incremental cash distributions above $0.3881
per common unit per quarter from 48% to 23%. As a result, any
such reduction in quarterly cash distributions from the
Partnership would have the effect of disproportionately reducing
the distributions that we receive from the Partnership based on
our IDRs as compared to distributions we receive from the
Partnership with respect to our 2% general partner interest and
our common units.

If the
Partnerships unitholders remove the General Partner, we
would lose our general partner interest and IDRs in the
Partnership and the ability to manage the
Partnership.

We currently manage our investment in the Partnership through
our ownership interest in the General Partner. The
Partnerships partnership agreement, however, gives
unitholders of the Partnership the right to remove the General
Partner upon the affirmative vote of holders of
662/3%
of the Partnerships outstanding units. If the General
Partner were removed as general partner of the Partnership, it
would receive cash or common units in exchange for its 2%
general partner interest and the IDRs and would also lose its
ability to manage the Partnership. While the cash or common
units the General Partner would receive are intended under the
terms of the Partnerships partnership agreement to fully
compensate us in the event such an exchange is required, the
value of the investments we make with the cash or the common
units may not over time be equivalent to the value of the
general partner interest and the IDRs had the General Partner
retained them. Please read Material Provisions of the
Partnerships Partnership AgreementWithdrawal or
Removal of the General Partner.

In addition, if the General Partner is removed as general
partner of the Partnership, we would face an increased risk of
being deemed an investment company. Please read If
in the future we cease to manage and control the Partnership, we
may be deemed to be an investment company under the Investment
Company Act of 1940.

The
Partnership, without our stockholders consent, may issue
additional common units or other equity securities, which may
increase the risk that the Partnership will not have sufficient
available cash to maintain or increase its cash distribution
level per common unit.

Because the Partnership distributes to its partners most of the
cash generated by its operations, it relies primarily upon
external financing sources, including debt and equity issuances,
to fund its acquisitions and expansion capital expenditures.
Accordingly, the Partnership has wide latitude to issue
additional common units on the terms and conditions established
by its general partner. We receive cash distributions from the
Partnership on the general partner interest, IDRs and common
units that we own. Because a significant portion of the cash we
receive from the Partnership is attributable to our ownership of
the IDRs, payment of distributions on additional Partnership
common units may increase the risk that the Partnership will be
unable to maintain or increase its quarterly cash distribution
per unit, which in turn may

reduce the amount of distributions we receive attributable to
our common units, general partner interest and IDRs and the
available cash that we have to distribute to our stockholders.

The General
Partner, with our consent but without the consent of our
stockholders, may limit or modify the incentive distributions we
are entitled to receive, which may reduce cash dividends to
you.

We own the General Partner, which owns the IDRs in the
Partnership that entitle us to receive increasing percentages,
up to a maximum of 48% of any cash distributed by the
Partnership as certain target distribution levels are reached in
excess of $0.3881 per common unit in any quarter. A substantial
portion of the cash flow we receive from the Partnership is
provided by these IDRs. Because of the high percentage of the
Partnerships incremental cash flow that is distributed to
the IDRs, certain potential acquisitions might not increase cash
available for distribution per Partnership unit. In order to
facilitate acquisitions by the Partnership or for other reasons,
the board of directors of the General Partner may elect to
reduce the IDRs payable to us with our consent. These reductions
may be permanent reductions in the IDRs or may be reductions
with respect to cash flows from the potential acquisition. If
distributions on the IDRs were reduced for the benefit of the
Partnership units, the total amount of cash distributions we
would receive from the Partnership, and therefore the amount of
cash distributions we could pay to our stockholders, would be
reduced.

In the future,
we may not have sufficient cash to pay estimated
dividends.

Because our only source of operating cash flow consists of cash
distributions from the Partnership, the amount of dividends we
are able to pay to our stockholders may fluctuate based on the
level of distributions the Partnership makes to its partners,
including us. The Partnership may not continue to make quarterly
distributions at the 2010 fourth quarter distribution level of
$0.5475 per common unit that management plans to recommend, or
may not distribute any other amount, or increase its quarterly
distributions in the future. In addition, while we would expect
to increase or decrease distributions to our stockholders if the
Partnership increases or decreases distributions to us, the
timing and amount of such changes in distributions, if any, will
not necessarily be comparable to the timing and amount of any
changes in distributions made by us. Factors such as reserves
established by our board of directors for our estimated general
and administrative expenses of being a public company as well as
other operating expenses, reserves to satisfy our debt service
requirements, if any, and reserves for future distributions by
us may affect the dividends we make to our stockholders. The
actual amount of cash that is available for dividends to our
stockholders will depend on numerous factors, many of which are
beyond our control.

Our cash
dividend policy limits our ability to grow.

Because we plan on distributing a substantial amount of our cash
flow, our growth may not be as fast as the growth of businesses
that reinvest their available cash to expand ongoing operations.
In fact, because our only cash-generating assets are direct and
indirect partnership interests in the Partnership, our growth
will be substantially dependent upon the Partnership. If we
issue additional shares of common stock or we were to incur
debt, the payment of dividends on those additional shares or
interest on that debt could increase the risk that we will be
unable to maintain or increase our cash dividend levels.

Our rate of
growth may be reduced to the extent we purchase additional units
from the Partnership, which will reduce the relative percentage
of the cash we receive from the IDRs.

Our business strategy includes, where appropriate, supporting
the growth of the Partnership by purchasing the
Partnerships units or lending funds or providing other
forms of financial support to the Partnership to provide funding
for the acquisition of a business or asset or for a growth
project. To the extent we purchase common units or securities
not entitled to a current distribution from the Partnership, the
rate of our distribution growth may be reduced, at least in the
short term, as less of our cash distributions will come from our
ownership of IDRs, whose distributions increase at a faster rate
than those of our other securities.

We have a
credit facility that contains various restrictions on our
ability to pay dividends to our stockholders, borrow additional
funds or capitalize on business opportunities.

We have a credit facility that contains various operating and
financial restrictions and covenants. Our ability to comply with
these restrictions and covenants may be affected by events
beyond our control, including prevailing economic, financial and
industry conditions. If we are unable to comply with these
restrictions and covenants, any future indebtedness under this
credit facility may become immediately due and payable and our
lenders commitment to make further loans to us may
terminate. We might not have, or be able to obtain, sufficient
funds to make these accelerated payments.

Our credit facility limits our ability to pay dividends to our
stockholders during an event of default or if an event of
default would result from such dividend.

limit our ability to pursue acquisitions and other business
opportunities;



make our results of operations more susceptible to adverse
economic or operating conditions; or



limit our ability to pay dividends.

Our payment of any principal and interest will reduce our cash
available for distribution to holders of common stock. In
addition, we are able to incur substantial additional
indebtedness in the future. If we incur additional debt, the
risks associated with our leverage would increase. For more
information regarding our credit facility, please read
Managements Discussion and Analysis of Financial
Condition and Results of OperationsLiquidity and Capital
Resources.

If dividends
on our shares of common stock are not paid with respect to any
fiscal quarter, including those at the anticipated initial
dividend rate, our stockholders will not be entitled to receive
that quarters payments in the future.

Dividends to our stockholders will not be cumulative.
Consequently, if dividends on our shares of common stock are not
paid with respect to any fiscal quarter, including those at the
anticipated initial distribution rate, our stockholders will not
be entitled to receive that quarters payments in the
future.

The
Partnerships practice of distributing all of its available
cash may limit its ability to grow, which could impact
distributions to us and the available cash that we have to
dividend to our stockholders.

Because our only cash-generating assets are common units and
general partner interests in the Partnership, including the
IDRs, our growth will be dependent upon the Partnerships
ability to increase its quarterly cash distributions. The
Partnership has historically distributed to its partners most of
the cash generated by its operations. As a result, it relies
primarily upon external financing sources, including debt and
equity issuances, to fund its acquisitions and expansion capital
expenditures. Accordingly, to the extent the Partnership is
unable to finance growth externally, its ability to grow will be
impaired because it distributes substantially all of its
available cash. Also, if the Partnership incurs additional
indebtedness to finance its growth, the increased interest
expense associated with such indebtedness may reduce the amount
of available cash that we can distribute to you. In addition, to
the extent the Partnership issues additional units in connection
with any acquisitions or growth capital expenditures, the
payment of distributions on those additional units may increase
the risk that the Partnership will be unable to maintain or
increase its per unit distribution level, which in turn may
impact the available cash that we have to distribute to our
stockholders.

Restrictions
in the Partnerships senior secured credit facility and
indentures could limit its ability to make distributions
to us.

The Partnerships senior secured credit facility and
indentures contain covenants limiting its ability to incur
indebtedness, grant liens, engage in transactions with
affiliates and make distributions. The Partnerships senior
secured credit facility also contains covenants requiring the
Partnership to maintain certain financial ratios. The
Partnership is prohibited from making any distribution to
unitholders if such distribution would cause an event of default
or otherwise violate a covenant under its senior secured credit
facility or the indentures.

If in the
future we cease to manage and control the Partnership, we may be
deemed to be an investment company under the Investment Company
Act of 1940.

If we cease to manage and control the Partnership and are deemed
to be an investment company under the Investment Company Act of
1940, we would either have to register as an investment company
under the Investment Company Act of 1940, obtain exemptive
relief from the SEC or modify our organizational structure or
our contractual rights to fall outside the definition of an
investment company. Registering as an investment company could,
among other things, materially limit our ability to engage in
transactions with affiliates, including the purchase and sale of
certain securities or other property to or from our affiliates,
restrict our ability to borrow funds or engage in other
transactions involving leverage and require us to add additional
directors who are independent of us and our affiliates, and
adversely affect the price of our common stock.

Our historical
and pro forma financial information may not be representative of
our future performance.

The historical financial information included in this prospectus
is derived from our historical financial statements for periods
prior to our initial public offering. Our audited historical
financial statements were prepared in accordance with GAAP.
Accordingly, the historical financial information included in
this prospectus does not reflect what our results of operations
and financial condition would have been had we been a public
entity during the periods presented, or what our results of
operations and financial condition will be in the future.

In preparing the pro forma financial information included in
this prospectus, we have made adjustments to our historical
financial information based upon currently available information
and upon assumptions that our management believes are reasonable
in order to reflect, on a pro forma basis, the impact of the
items discussed in our unaudited pro forma financial statements
and related notes. The estimates and assumptions used in the
calculation of the pro forma financial information in this
prospectus may be materially different from our actual
experience as a public entity. Accordingly, the pro forma
financial information included in this prospectus does not
purport to represent what our results of operations would
actually have been had we operated as a public entity during the
periods presented or what our results of operations and
financial condition will be in the future, nor does the pro
forma financial information give effect to any events other than
those discussed in our unaudited pro forma financial statements
and related notes.

The
assumptions underlying our TRC minimum estimated cash available
for distribution for the three month period ending
December 31, 2010 and the twelve month period ending
December 31, 2011, included in Our Dividend
Policy involve inherent and significant business,
economic, financial, regulatory and competitive risks and
uncertainties that could cause actual results to differ
materially from those estimated.

Our estimate of cash available for distribution for the three
month period ending December 31, 2010 and the twelve month
period ending December 31, 2011 set forth in Our
Dividend Policy has been prepared by management, and we
have not received an opinion or report on it from our or any
other independent registered public accounting firm. The
assumptions underlying the forecasts are inherently

uncertain and are subject to significant business, economic,
financial, regulatory and competitive risks and uncertainties
that could cause actual results to differ materially from those
forecasted. If we do not achieve the forecasted results, we may
not be able to pay a quarterly dividend on our common stock, in
which event the market price of our common stock may decline
materially. For further discussion on our ability to pay a
quarterly dividend, please read Our Dividend Policy.

If we lose any
of our named executive officers, our business may be adversely
affected.

Our success is dependent upon the efforts of the named executive
officers. Our named executive officers are responsible for
executing the Partnerships business strategy and, when
appropriate to our primary business objective, facilitating the
Partnerships growth through various forms of financial
support provided by us, including, but not limited to, modifying
the Partnerships IDRs, exercising the Partnerships
IDR reset provision contained in its partnership agreement,
making loans, making capital contributions in exchange for
yielding or non-yielding equity interests or providing other
financial support to the Partnership. There is substantial
competition for qualified personnel in the midstream natural gas
industry. We may not be able to retain our existing named
executive officers or fill new positions or vacancies created by
expansion or turnover. We have not entered into employment
agreements with any of our named executive officers. In
addition, we do not maintain key man life insurance
on the lives of any of our named executive officers. A loss of
one or more of our named executive officers could harm our and
the Partnerships business and prevent us from implementing
our and the Partnerships business strategy.

If we fail to
develop or maintain an effective system of internal controls, we
may not be able to accurately report our financial results or
prevent fraud. In addition, potential changes in accounting
standards might cause us to revise our financial results and
disclosure in the future.

Effective internal controls are necessary for us to provide
timely and reliable financial reports and effectively prevent
fraud. If we cannot provide timely and reliable financial
reports or prevent fraud, our reputation and operating results
would be harmed. We continue to enhance our internal controls
and financial reporting capabilities. These enhancements require
a significant commitment of resources, personnel and the
development and maintenance of formalized internal reporting
procedures to ensure the reliability of our financial reporting.
Our efforts to update and maintain our internal controls may not
be successful, and we may be unable to maintain adequate
controls over our financial processes and reporting in the
future, including future compliance with the obligations under
Section 404 of the Sarbanes-Oxley Act of 2002. Any failure
to develop or maintain effective controls, or difficulties
encountered in their implementation or other effective
improvement of our internal controls could prevent us from
timely and reliably reporting our financial results and may harm
our operating results. Ineffective internal controls could also
cause investors to lose confidence in our reported financial
information. In addition, the Financial Accounting Standards
Board or the SEC could enact new accounting standards that might
impact how we or the Partnership are required to record
revenues, expenses, assets and liabilities. Any significant
change in accounting standards or disclosure requirements could
have a material effect on our business, results of operations,
financial condition and ability to service our and our
subsidiaries debt obligations.

Our shares of
common stock and the Partnerships common units may not
trade in relation or proportion to one another.

The shares of our common stock and the Partnerships common
units may not trade, either by volume or price, in correlation
or proportion to one another. Instead, while the trading prices
of our common stock and the Partnerships common units may
follow generally similar broad trends, the trading prices may
diverge because, among other things:



the Partnerships cash distributions to its common
unitholders have a priority over distributions on its IDRs;

we participate in the distributions on the General
Partners general partner interest and IDRs in the
Partnership while the Partnerships common unitholders do
not;



we and our stockholders are taxed differently from the
Partnership and its common unitholders; and



we may enter into other businesses separate and apart from the
Partnership or any of its affiliates.

An increase in
interest rates may cause the market price of our common stock to
decline.

Like all equity investments, an investment in our common stock
is subject to certain risks. In exchange for accepting these
risks, investors may expect to receive a higher rate of return
than would otherwise be obtainable from lower-risk investments.
Accordingly, as interest rates rise, the ability of investors to
obtain higher risk-adjusted rates of return by purchasing
government-backed debt securities may cause a corresponding
decline in demand for riskier investments generally, including
yield-based equity investments. Reduced demand for our common
stock resulting from investors seeking other more favorable
investment opportunities may cause the trading price of our
common stock to decline.

The initial
public offering price of our common stock may not be indicative
of the market price of our common stock after this offering. In
addition, an active liquid trading market for our common stock
may not develop and our stock price may be
volatile.

Prior to this offering, our common stock was not traded on any
market. An active and liquid trading market for our common stock
may not develop or be maintained after this offering. Liquid and
active trading markets usually result in less price volatility
and more efficiency in carrying out investors purchase and
sale orders. The market price of our common stock could vary
significantly as a result of a number of factors, some of which
are beyond our control. In the event of a drop in the market
price of our common stock, you could lose a substantial part or
all of your investment in our common stock. The initial public
offering price will be negotiated between the selling
stockholders and representatives of the underwriters, based on
numerous factors which are discussed in the
Underwriting section of this prospectus, and may not
be indicative of the market price of our common stock after this
offering. Consequently, you may not be able to sell shares of
our common stock at prices equal to or greater than the price
paid by you in the offering.

The following factors could affect our stock price:



our and the Partnerships operating and financial
performance;



quarterly variations in the rate of growth of our and the
Partnerships financial indicators, such as net income per
share, net income and revenues;



changes in revenue or earnings estimates or publication of
reports by equity research analysts relating to us or the
Partnership;



speculation in the press or investment community;



sales of our common stock by us, the selling stockholders or
other stockholders, or the perception that such sales may occur;



general market conditions, including fluctuations in commodity
prices; and



domestic and international economic, legal and regulatory
factors unrelated to our performance.

The stock markets in general have experienced volatility that
has often been unrelated to the operating performance of
particular companies. These broad market fluctuations may
adversely affect the trading price of our common stock.

The
requirements of being a public company, including compliance
with the reporting requirements of the Exchange Act and the
requirements of the Sarbanes-Oxley Act, may strain our
resources, increase our costs and distract management; and we
may be unable to comply with these requirements in a timely or
cost-effective manner.

As a public company with listed equity securities, we will need
to comply with new laws, regulations and requirements, certain
corporate governance provisions of the Sarbanes-Oxley Act of
2002, related regulations of the SEC and the requirements of the
New York Stock Exchange, or NYSE, with which we were not
required to comply as a private company. Complying with these
statutes, regulations and requirements will occupy a significant
amount of time of our board of directors and management and will
significantly increase our costs and expenses. We will need to:



institute a more comprehensive compliance function;



design, establish, evaluate and maintain an additional system of
internal controls over financial reporting in compliance with
the requirements of Section 404 of the Sarbanes-Oxley Act
of 2002 and the related rules and regulations of the SEC and the
Public Company Accounting Oversight Board;



comply with rules promulgated by the NYSE;



prepare and distribute periodic public reports in compliance
with our obligations under the federal securities laws;



establish new internal policies, such as those relating to
disclosure controls and procedures and insider trading;



involve and retain to a greater degree outside counsel and
accountants in the above activities; and



augment our investor relations function.

In addition, we also expect that being a public company will
require us to accept less director and officer liability
insurance coverage than we desire or to incur additional costs
to maintain coverage. These factors could also make it more
difficult for us to attract and retain qualified members of our
board of directors, particularly to serve on our Audit
Committee, and qualified executive officers.

Future sales
of our common stock in the public market could lower our stock
price, and any additional capital raised by us through the sale
of equity or convertible securities may dilute your ownership in
us.

We or our stockholders may sell shares of common stock in
subsequent public offerings. We may also issue additional shares
of common stock or convertible securities. After the completion
of this offering, we will have 42,292,381 outstanding shares of
common stock. This number consists of 13,750,000 shares
that the selling stockholders are selling in this offering
(assuming no exercise of the underwriters over-allotment
option), which may be resold immediately in the public market.
Following the completion of this offering, the existing
stockholders will own approximately 29 million shares, or
approximately 67.5% of our total outstanding shares, all of
which are restricted from immediate resale under the federal
securities laws. A substantial portion of such shares are
subject to the
lock-up
agreements between such parties and the underwriters described
in Underwriting, but may be sold into the market in
the future. Certain of our existing stockholders are party to a
registration rights agreement with us which requires us to
effect the registration of their shares in certain circumstances
no earlier than the expiration of the
lock-up
period contained in the underwriting agreement entered into in
connection with this offering.

As soon as practicable after this offering, we intend to file a
registration statement with the SEC on
Form S-8
providing for the registration of 5 million shares of our
common stock issued or reserved for issuance under our stock
incentive plan. Subject to the satisfaction of vesting
conditions and the expiration

of lock-up
agreements, shares registered under this registration statement
on
Form S-8
will be available for resale immediately in the public market
without restriction.

We cannot predict the size of future issuances of our common
stock or the effect, if any, that future issuances and sales of
shares of our common stock will have on the market price of our
common stock. Sales of substantial amounts of our common stock
(including shares issued in connection with an acquisition), or
the perception that such sales could occur, may adversely affect
prevailing market prices of our common stock.

Our amended
and restated certificate of incorporation and amended and
restated bylaws, as well as Delaware law, will contain
provisions that could discourage acquisition bids or merger
proposals, which may adversely affect the market price of our
common stock.

Our amended and restated certificate of incorporation will
authorize our board of directors to issue preferred stock
without stockholder approval. If our board of directors elects
to issue preferred stock, it could be more difficult for a third
party to acquire us. In addition, some provisions of our amended
and restated certificate of incorporation and amended and
restated bylaws could make it more difficult for a third party
to acquire control of us, even if the change of control would be
beneficial to our stockholders, including:



a classified board of directors, so that only approximately
one-third of our directors are elected each year;



limitations on the removal of directors; and



limitations on the ability of our stockholders to call special
meetings and establish advance notice provisions for stockholder
proposals and nominations for elections to the board of
directors to be acted upon at meetings of stockholders.

Delaware law prohibits us from engaging in any business
combination with any interested stockholder, meaning
generally that a stockholder who beneficially owns more than 15%
of our stock cannot acquire us for a period of three years from
the date this person became an interested stockholder, unless
various conditions are met, such as approval of the transaction
by our board of directors. We anticipate opting out of this
provision of Delaware law until such time as Warburg Pincus and
certain transferees, do not beneficially own at least 15% of our
common stock. Please read Description of Our Capital
StockAnti-Takeover Effects of Provisions of Our Amended
and Restated Certificate of Incorporation, Our Amended and
Restated Bylaws and Delaware Law.

Merrill Lynch,
Pierce, Fenner & Smith Incorporated may have a
conflict of interest with respect to this
offering.

Merrill Lynch Ventures L.P. 2001 (ML Ventures), an
affiliate of Merrill Lynch, Pierce, Fenner & Smith
Incorporated (BofA Merrill Lynch), an underwriter in
this offering, is selling 1,110,280 shares of common stock
in connection with this offing and will own
1,652,159 shares of our common stock, representing a 3.9%
ownership interest in us on a fully diluted basis upon
completion of this offering. Accordingly, BofA Merrill
Lynchs interest may go beyond receiving customary
underwriting discounts and commissions. In particular, there may
be a conflict of interest between BofA Merrill Lynchs own
interests as underwriter (including in negotiating the initial
public offering price) and the interests of its affiliate ML
Ventures as a selling stockholder. Because of this relationship,
this offering is being conducted in accordance with
Rule 2720 of the NASD Conduct Rules (which are part of the
FINRA Rules). This rule requires, among other things, that a
qualified independent underwriter has participated in the
preparation of, and has exercised the usual standards of due
diligence with respect to, this prospectus and the registration
statement of which this prospectus is a part. Accordingly,
Barclays Capital Inc. (Barclays Capital) is assuming the
responsibilities of acting as the qualified independent
underwriter in this offering. Although the qualified independent
underwriter has participated in the preparation of the
registration statement and prospectus and conducted due
diligence, we cannot assure you that this will adequately

address any potential conflicts of interest related to BofA
Merrill Lynch and ML Ventures. We have agreed to indemnify
Barclays Capital for acting as qualified independent underwriter
against certain liabilities, including liabilities under the
Securities Act and to contribute to payments that Barclays
Capital may be required to make for these liabilities.

We have a
significant stockholder, which will limit your ability to
influence corporate matters and may give rise to conflicts of
interest.

Upon completion of this offering, affiliates of Warburg Pincus
will beneficially own approximately 44.0% of our outstanding
common stock based on the assumed rate of conversion of our
preferred stock into common stock upon completion of this
offering as described under SummaryOur Structure and
Ownership After This Offering. See Security
Ownership of Management and Selling Stockholders.
Accordingly, Warburg Pincus will exert significant influence
over us and any action requiring the approval of the holders of
our stock, including the election of directors and approval of
significant corporate transactions. Warburgs concentrated
ownership makes it less likely that any other holder or group of
holders of common stock will be able to affect the way we are
managed or the direction of our business. These factors also may
delay or prevent a change in our management or voting control.

Furthermore, conflicts of interest could arise in the future
between us, on the one hand, and Warburg Pincus and its
affiliates, on the other hand, concerning among other things,
potential competitive business activities, business
opportunities, the issuance of additional securities, the
payment of dividends by us and other matters. Warburg Pincus is
a private equity firm that has invested, among other things, in
companies in the energy industry. As a result, Warburg
Pincus existing and future portfolio companies which it
controls may compete with us for investment or business
opportunities. These conflicts of interest may not be resolved
in our favor.

In our amended
and restated certificate of incorporation, we have renounced
business opportunities that may be pursued by the Partnership or
by affiliated stockholders that currently hold a significant
amount of our common stock.

In our restated charter and in accordance with Delaware law, we
have renounced any interest or expectancy we may have in, or
being offered an opportunity to participate in, any business
opportunities, including any opportunities within those classes
of opportunity currently pursued by the Partnership, presented
to Warburg Pincus or any private fund that it manages or
advises, their affiliates (other than us and our subsidiaries),
their officers, directors, partners, employees or other agents
who serve as one of our directors, Merrill Lynch Ventures L.P.
2001, its affiliates (other than us and our subsidiaries), and
any portfolio company in which such entities or persons has an
equity investment (other than us and our subsidiaries)
participates or desires or seeks to participate in and that
involves any aspect of the energy business or industry. Please
read Description of Our Capital StockCorporate
Opportunity.

The duties of
our officers and directors may conflict with those owed to the
Partnership and these officers and directors may face conflicts
of interest in the allocation of administrative time among our
business and the Partnerships business.

We anticipate that substantially all of our officers and certain
members of our board of directors will be officers or directors
of the General Partner and, as a result, will have separate
duties that govern their management of the Partnerships
business. These officers and directors may encounter situations
in which their obligations to us, on the one hand, and the
Partnership, on the other hand, are in conflict. For a
description of how these conflicts will be resolved, please read
Certain Relationships and Related
TransactionsConflicts of Interest. The resolution of
these conflicts may not always be in our best interest or that
of our stockholders.

In addition, our officers who also serve as officers of the
General Partner may face conflicts in allocating their time
spent on our behalf and on behalf of the Partnership. These time
allocations may adversely affect our or the Partnerships
results of operations, cash flows, and financial condition. For
a list

of our officers and directors that will serve in the same
capacity for the General Partner and a discussion of the amount
of time we expect them to devote to our business, please read
Management.

The U.S.
federal income tax rate on dividend income is scheduled to
increase in 2011.

Our distributions to our stockholders will constitute dividends
for U.S. federal income tax purposes to the extent such
distributions are paid from our current or accumulated earnings
and profits, as determined under U.S. federal income tax
principles. Dividends received by certain non-corporate
U.S. stockholders, including individuals, are subject to a
reduced maximum federal tax rate of 15% for taxable years
beginning on or before December 31, 2010. However, for
taxable years beginning after December 31, 2010, dividends
received by such non-corporate U.S. stockholders will be
taxed at the rate applicable to ordinary income of individuals,
which is scheduled to increase to a maximum of 39.6%.

Risks Inherent in
the Partnerships Business

Because we are directly dependent on the distributions we
receive from the Partnership, risks to the Partnerships
operations are also risks to us. We have set forth below risks
to the Partnerships business and operations, the
occurrence of which could negatively impact the
Partnerships financial performance and decrease the amount
of cash it is able to distribute to us.

The
Partnership has a substantial amount of indebtedness which may
adversely affect its financial position.

The Partnership has a substantial amount of indebtedness. On
July 19, 2010, the Partnership entered into a new five-year
$1.1 billion senior secured revolving credit facility,
which allows it to request increases in commitments up to an
additional $300 million. The amended and restated senior
secured credit facility replaces the Partnerships former
$977.5 million senior secured revolving credit facility due
February 2012. As of September 30, 2010, the Partnership
had approximately $753 million of borrowings outstanding
under its senior secured credit facility, approximately
$102 million of letters of credit outstanding and
approximately $245 million of additional borrowing capacity
under its senior secured credit facility. For the year ended
December 31, 2009 and the quarter ended September 30,
2010, the Partnerships consolidated interest expense was
$118.6 million and $23.3 million.

This substantial level of indebtedness increases the possibility
that the Partnership may be unable to generate cash sufficient
to pay, when due, the principal of, interest on or other amounts
due in respect of indebtedness. This substantial indebtedness,
combined with the Partnerships lease and other financial
obligations and contractual commitments, could have other
important consequences to us, including the following:



the Partnerships ability to obtain additional financing,
if necessary, for working capital, capital expenditures,
acquisitions or other purposes may be impaired or such financing
may not be available on favorable terms;



satisfying the Partnerships obligations with respect to
indebtedness may be more difficult and any failure to comply
with the obligations of any debt instruments could result in an
event of default under the agreements governing such
indebtedness;



the Partnership will need a portion of cash flow to make
interest payments on debt, reducing the funds that would
otherwise be available for operations and future business
opportunities;



the Partnerships debt level will make it more vulnerable
to competitive pressures or a downturn in its business or the
economy generally; and



the Partnerships debt level may limit flexibility in
planning for, or responding to, changing business and economic
conditions.

The Partnerships ability to service its debt will depend
upon, among other things, its future financial and operating
performance, which will be affected by prevailing economic
conditions and

financial, business, regulatory and other factors, some of which
are beyond its control. If the Partnerships operating
results are not sufficient to service its current or future
indebtedness, it will be forced to take actions such as reducing
or delaying business activities, acquisitions, investments or
capital expenditures, selling assets, restructuring or
refinancing debt, or seeking additional equity capital and may
adversely affect the Partnerships ability to make cash
distributions. The Partnership may not be able to effect any of
these actions on satisfactory terms, or at all.

Increases in
interest rates could adversely affect the Partnerships
business.

The Partnership has significant exposure to increases in
interest rates. As of September 30, 2010, its total
indebtedness was $1,433.2 million, of which
$679.9 million was at fixed interest rates and
$753.3 million was at variable interest rates. After giving
effect to interest rate swaps with a notional amount of
$300 million, a one percentage point increase in the
interest rate on the Partnerships variable interest rate
debt would have increased its consolidated annual interest
expense by approximately $4.5 million. As a result of this
significant amount of variable interest rate debt, the
Partnerships financial condition could be adversely
affected by significant increases in interest rates.

Despite
current indebtedness levels, the Partnership may still be able
to incur substantially more debt. This could increase the risks
associated with its substantial leverage.

The Partnership may be able to incur substantial additional
indebtedness in the future. As of September 30, 2010, the
Partnership had approximately $753 million of borrowings
outstanding under its senior secured credit facility,
approximately, $102 million of letters of credit
outstanding and approximately $245 million of additional
borrowing capacity. The Partnership may be able to incur an
additional $300 million of debt under its senior secured
credit facility if it requests and is able to obtain commitments
for the additional $300 million available under its senior
secured credit facility. Although the Partnerships senior
secured credit facility contains restrictions on the incurrence
of additional indebtedness, these restrictions are subject to a
number of significant qualifications and exceptions, and any
indebtedness incurred in compliance with these restrictions
could be substantial. If the Partnership incurs additional debt,
the risks associated with its substantial leverage would
increase.

The terms of
the Partnerships senior secured credit facility and
indentures may restrict its current and future operations,
particularly its ability to respond to changes in business or to
take certain actions.

The credit agreement governing the Partnerships senior
secured credit facility and the indentures governing the
Partnerships senior notes contain, and any future
indebtedness the Partnership incurs will likely contain, a
number of restrictive covenants that impose significant
operating and financial restrictions, including restrictions on
its ability to engage in acts that may be in its best long-term
interests. These agreements include covenants that, among other
things, restrict the Partnerships ability to:



incur or guarantee additional indebtedness or issue preferred
stock;



pay dividends on its equity securities or redeem, repurchase or
retire its equity securities or subordinated indebtedness;



make investments;



create restrictions on the payment of dividends or other
distributions to its equity holders;

prepay, redeem and repurchase certain debt, other than loans
under the senior secured credit facility;



make certain acquisitions;



transfer assets;



enter into sale and lease back transactions;



make capital expenditures;



amend debt and other material agreements; and



change business activities conducted by it.

In addition, the Partnerships senior secured credit
facility requires it to satisfy and maintain specified financial
ratios and other financial condition tests. The
Partnerships ability to meet those financial ratios and
tests can be affected by events beyond its control, and we
cannot assure you that the Partnership will meet those ratios
and tests.

A breach of any of these covenants could result in an event of
default under the Partnerships senior secured credit
facility and indentures. Upon the occurrence of such an event of
default, all amounts outstanding under the applicable debt
agreements could be declared to be immediately due and payable
and all applicable commitments to extend further credit could be
terminated. If the Partnership is unable to repay the
accelerated debt under its senior secured credit facility, the
lenders under senior secured credit facility could proceed
against the collateral granted to them to secure that
indebtedness. The Partnership has pledged substantially all of
its assets as collateral under its senior secured credit
facility. If the Partnership indebtedness under its senior
secured credit facility or indentures is accelerated, we cannot
assure you that the Partnership will have sufficient assets to
repay the indebtedness. The operating and financial restrictions
and covenants in these debt agreements and any future financing
agreements may adversely affect the Partnerships ability
to finance future operations or capital needs or to engage in
other business activities.

The
Partnerships cash flow is affected by supply and demand
for natural gas and NGL products and by natural gas and NGL
prices, and decreases in these prices could adversely affect its
results of operations and financial condition.

The Partnerships operations can be affected by the level
of natural gas and NGL prices and the relationship between these
prices. The prices of oil, natural gas and NGLs have been
volatile and we expect this volatility to continue. The
Partnerships future cash flow may be materially adversely
affected if it experiences significant, prolonged pricing
deterioration. The markets and prices for natural gas and NGLs
depend upon factors beyond the Partnerships control. These
factors include demand for these commodities, which fluctuate
with changes in market and economic conditions and other
factors, including:

the availability and marketing of competitive fuels
and/or
feedstocks;



the impact of energy conservation efforts; and



the extent of governmental regulation and taxation.

The Partnerships primary natural gas gathering and
processing arrangements that expose it to commodity price risk
are its
percent-of-proceeds
arrangements. For the nine months ended September 30, 2010
and the year ended December 31, 2009, its
percent-of-proceeds
arrangements accounted for approximately 37% and 48% of its
gathered natural gas volume. Under
percent-of-proceeds
arrangements, the Partnership generally processes natural gas
from producers and remits to the producers an agreed percentage
of the proceeds from the sale of residue gas and NGL products at
market prices or a percentage of residue gas and NGL products at
the tailgate of its processing facilities. In some
percent-of-proceeds
arrangements, the Partnership remits to the producer a
percentage of an index-based price for residue gas and NGL
products, less agreed adjustments, rather than remitting a
portion of the actual sales proceeds. Under these types of
arrangements, the Partnerships revenues and its cash flows
increase or decrease, whichever is applicable, as the price of
natural gas, NGLs and crude oil fluctuates. Please see
Managements Discussion and Analysis of Financial
Condition and Results of OperationsQuantitative and
Qualitative Disclosures about Market Risk.

Because of the
natural decline in production in the Partnerships
operating regions and in other regions from which it sources NGL
supplies, the Partnerships long-term success depends on
its ability to obtain new sources of supplies of natural gas and
NGLs, which depends on certain factors beyond its control. Any
decrease in supplies of natural gas or NGLs could adversely
affect the Partnerships business and operating
results.

The Partnerships gathering systems are connected to oil
and natural gas wells from which production will naturally
decline over time, which means that its cash flows associated
with these sources of natural gas will likely also decline over
time. The Partnerships logistics assets are similarly
impacted by declines in NGL supplies in the regions in which the
Partnership operates as well as other regions from which it
sources NGLs. To maintain or increase throughput levels on its
gathering systems and the utilization rate at its processing
plants and its treating and fractionation facilities, the
Partnership must continually obtain new natural gas and NGL
supplies. A material decrease in natural gas production from
producing areas on which the Partnership relies, as a result of
depressed commodity prices or otherwise, could result in a
decline in the volume of natural gas that it processes and NGL
products delivered to its fractionation facilities. The
Partnerships ability to obtain additional sources of
natural gas and NGLs depends, in part, on the level of
successful drilling and production activity near its gathering
systems and, in part, on the level of successful drilling and
production in other areas from which it sources NGL supplies.
The Partnership has no control over the level of such activity
in the areas of its operations, the amount of reserves
associated with the wells or the rate at which production from a
well will decline. In addition, the Partnership has no control
over producers or their drilling or production decisions, which
are affected by, among other things, prevailing and projected
energy prices, demand for hydrocarbons, the level of reserves,
geological considerations, governmental regulations,
availability of drilling rigs, other production and development
costs and the availability and cost of capital.

Fluctuations in energy prices can greatly affect production
rates and investments by third parties in the development of new
oil and natural gas reserves. Drilling and production activity
generally decreases as oil and natural gas prices decrease.
Prices of oil and natural gas have been volatile, and the
Partnership expects this volatility to continue. Consequently,
even if new natural gas reserves are discovered in areas served
by the Partnerships assets, producers may choose not to
develop those reserves. Reductions in exploration and production
activity, competitor actions or shut-ins by producers in the
areas in which the Partnership operates may prevent it from
obtaining supplies of natural gas to replace the natural decline
in volumes from existing wells, which could result in reduced
volumes through its facilities, and reduced utilization of its
gathering, treating, processing and fractionation assets.

If the
Partnership does not make acquisitions on economically
acceptable terms or efficiently and effectively integrate the
acquired assets with its asset base, its future growth will be
limited.

The Partnerships ability to grow depends, in part, on its
ability to make acquisitions that result in an increase in cash
generated from operations per unit. The Partnership is unable to
acquire businesses from us in order to grow because our only
assets are the interests in the Partnership that we own. As a
result, it will need to focus on third-party acquisitions and
organic growth. If the Partnership is unable to make these
accretive acquisitions either because the Partnership is
(1) unable to identify attractive acquisition candidates or
negotiate acceptable purchase contracts with them,
(2) unable to obtain financing for these acquisitions on
economically acceptable terms or (3) outbid by competitors,
then its future growth and ability to increase distributions
will be limited.

Any acquisition involves potential risks, including, among other
things:

the diversion of managements and employees attention
from other business concerns; and



customer or key employee losses at the acquired businesses.

If these risks materialize, the acquired assets may inhibit the
Partnerships growth, fail to deliver expected benefits and
add further unexpected costs. Challenges may arise whenever
businesses with different operations or management are combined
and the Partnership may experience unanticipated delays in
realizing the benefits of an acquisition. If the Partnership
consummates any future acquisition, its capitalization and
results of operations may change significantly and you may not
have the opportunity to evaluate the economic, financial and
other relevant information that the Partnership will consider in
evaluating future acquisitions.

The Partnerships acquisition strategy is based, in part,
on its expectation of ongoing divestitures of energy assets by
industry participants. A material decrease in such divestitures
would limit its opportunities for future acquisitions and could
adversely affect its operations and cash flows available for
distribution to its unitholders.

Acquisitions may significantly increase the Partnerships
size and diversify the geographic areas in which it operates.
The Partnership may not achieve the desired affect from any
future acquisitions.

The
Partnerships construction of new assets may not result in
revenue increases and is subject to regulatory, environmental,
political, legal and economic risks, which could adversely
affect its results of operations and financial
condition.

One of the ways the Partnership intends to grow its business is
through the construction of new midstream assets. The
construction of additions or modifications to the
Partnerships existing systems and

the construction of new midstream assets involves numerous
regulatory, environmental, political and legal uncertainties
beyond the Partnerships control and may require the
expenditure of significant amounts of capital. If the
Partnership undertakes these projects, they may not be completed
on schedule or at the budgeted cost or at all. Moreover, the
Partnerships revenues may not increase immediately upon
the expenditure of funds on a particular project. For instance,
if the Partnership builds a new pipeline, the construction may
occur over an extended period of time and it will not receive
any material increases in revenues until the project is
completed. Moreover, it may construct facilities to capture
anticipated future growth in production in a region in which
such growth does not materialize. Since the Partnership is not
engaged in the exploration for and development of natural gas
and oil reserves, it does not possess reserve expertise and it
often does not have access to third party estimates of potential
reserves in an area prior to constructing facilities in such
area. To the extent the Partnership relies on estimates of
future production in its decision to construct additions to its
systems, such estimates may prove to be inaccurate because there
are numerous uncertainties inherent in estimating quantities of
future production. As a result, new facilities may not be able
to attract enough throughput to achieve the Partnerships
expected investment return, which could adversely affect its
results of operations and financial condition. In addition, the
construction of additions to the Partnerships existing
gathering and transportation assets may require it to obtain new
rights-of-way
prior to constructing new pipelines. The Partnership may be
unable to obtain such
rights-of-way
to connect new natural gas supplies to its existing gathering
lines or capitalize on other attractive expansion opportunities.
Additionally, it may become more expensive for the Partnership
to obtain new
rights-of-way
or to renew existing
rights-of-way.
If the cost of renewing or obtaining new
rights-of-way
increases, the Partnerships cash flows could be adversely
affected.

The
Partnerships acquisition strategy requires access to new
capital. Tightened capital markets or increased competition for
investment opportunities could impair its ability to grow
through acquisitions.

The Partnership continuously considers and enters into
discussions regarding potential acquisitions. Any limitations on
its access to capital will impair its ability to execute this
strategy. If the cost of such capital becomes too expensive, its
ability to develop or acquire strategic and accretive assets
will be limited. The Partnership may not be able to raise the
necessary funds on satisfactory terms, if at all. The primary
factors that influence the Partnerships initial cost of
equity include market conditions, fees it pays to underwriters
and other offering costs, which include amounts it pays for
legal and accounting services. The primary factors influencing
the Partnerships cost of borrowing include interest rates,
credit spreads, covenants, underwriting or loan origination fees
and similar charges it pays to lenders.

Current weak economic conditions and the volatility and
disruption in the weak financial markets have increased the cost
of raising money in the debt and equity capital markets
substantially while diminishing the availability of funds from
those markets. Also, as a result of concerns about the stability
of financial markets generally and the solvency of
counterparties specifically, the cost of obtaining money from
the credit markets generally has increased as many lenders and
institutional investors have increased interest rates, enacted
tighter lending standards, refused to refinance existing debt at
maturity at all or on terms similar to our current debt and
reduced and, in some cases, ceased to provide funding to
borrowers. These factors may impair the Partnerships
ability to execute its acquisition strategy.

Global financial markets and economic conditions have been, and
continue to be, disrupted and volatile. The debt and equity
capital markets have been exceedingly distressed. These issues,
along with significant write-offs in the financial services
sector, the re-pricing of credit risk and the current weak
economic conditions have made, and will likely continue to make,
it difficult to obtain funding.

In particular, the cost of raising money in the debt and equity
capital markets has increased substantially while the
availability of funds from those markets generally has
diminished significantly. Also, as a result of concerns about
the stability of financial markets generally and the solvency of
counterparties specifically, the cost of obtaining funds from
the credit markets generally has increased as many lenders and
institutional investors have increased interest rates, enacted
tighter lending standards, refused to refinance

existing debt at maturity at all or on terms similar to the
Partnerships current debt and reduced and, in some cases,
ceased to provide funding to borrowers.

In addition, the Partnership is experiencing increased
competition for the types of assets it contemplates purchasing.
The weak economic conditions and competition for asset purchases
could limit the Partnerships ability to fully execute its
growth strategy. The Partnerships inability to execute its
growth strategy could materially adversely affect its ability to
maintain or pay higher distributions in the future.

Demand for
propane is seasonal and requires increases in inventory to meet
seasonal demand.

Weather conditions have a significant impact on the demand for
propane because end-users depend on propane principally for
heating purposes.
Warmer-than-normal
temperatures in one or more regions in which the Partnership
operates can significantly decrease the total volume of propane
it sells. Lack of consumer demand for propane may also adversely
affect the retailers the Partnership transacts with in its
wholesale propane marketing operations, exposing it to their
inability to satisfy their contractual obligations to the
Partnership.

If the
Partnership fails to balance its purchases of natural gas and
its sales of residue gas and NGLs, its exposure to commodity
price risk will increase.

The Partnership may not be successful in balancing its purchases
of natural gas and its sales of residue gas and NGLs. In
addition, a producer could fail to deliver promised volumes to
the Partnership or deliver in excess of contracted volumes, or a
purchaser could purchase less than contracted volumes. Any of
these actions could cause an imbalance between the
Partnerships purchases and sales. If the
Partnerships purchases and sales are not balanced, it will
face increased exposure to commodity price risks and could have
increased volatility in its operating income.

The
Partnerships hedging activities may not be effective in
reducing the variability of its cash flows and may, in certain
circumstances, increase the variability of its cash flows.
Moreover, the Partnerships hedges may not fully protect it
against volatility in basis differentials. Finally, the
percentage of the Partnerships expected equity commodity
volumes that are hedged decreases substantially over
time.

The Partnership has entered into derivative transactions related
to only a portion of its equity volumes. As a result, it will
continue to have direct commodity price risk to the unhedged
portion. The Partnerships actual future volumes may be
significantly higher or lower than it estimated at the time it
entered into the derivative transactions for that period. If the
actual amount is higher than it estimated, it will have greater
commodity price risk than it intended. If the actual amount is
lower than the amount that is subject to its derivative
financial instruments, it might be forced to satisfy all or a
portion of its derivative transactions without the benefit of
the cash flow from its sale of the underlying physical
commodity. The percentages of the Partnerships expected
equity volumes that are covered by its hedges decrease over
time. To the extent the Partnership hedges its commodity price
risk, it may forego the benefits it would otherwise experience
if commodity prices were to change in its favor. The derivative
instruments the Partnership utilizes for these hedges are based
on posted market prices, which may be higher or lower than the
actual natural gas, NGLs and condensate prices that it realizes
in its operations. These pricing differentials may be
substantial and could materially impact the prices the
Partnership ultimately realizes. In addition, current market and
economic conditions may adversely affect the Partnerships
hedge counterparties ability to meet their obligations.
Given the current volatility in the financial and commodity
markets, the Partnership may experience defaults by its hedge
counterparties in the future. As a result of these and other
factors, the Partnerships hedging activities may not be as
effective as it intends in reducing the variability of its cash
flows, and in certain circumstances may actually increase the
variability of its cash flows. Please see
Managements Discussion and Analysis of Financial
Condition and Results of OperationsQuantitative and
Qualitative Disclosures about Market Risk.

If third party
pipelines and other facilities interconnected to the
Partnerships natural gas pipelines and processing
facilities become partially or fully unavailable to transport
natural gas and NGLs, the Partnerships revenues could be
adversely affected.

The Partnership depends upon third party pipelines, storage and
other facilities that provide delivery options to and from its
pipelines and processing facilities. Since it does not own or
operate these pipelines or other facilities, their continuing
operation in their current manner is not within the
Partnerships control. If any of these third party
facilities become partially or fully unavailable, or if the
quality specifications for their facilities change so as to
restrict the Partnerships ability to utilize them, its
revenues could be adversely affected.

The
Partnerships industry is highly competitive, and increased
competitive pressure could adversely affect the
Partnerships business and operating results.

The Partnership competes with similar enterprises in its
respective areas of operation. Some of its competitors are large
oil, natural gas and natural gas liquid companies that have
greater financial resources and access to supplies of natural
gas and NGLs than it does. Some of these competitors may expand
or construct gathering, processing and transportation systems
that would create additional competition for the services the
Partnership provides to its customers. In addition, its
customers who are significant producers of natural gas may
develop their own gathering, processing and transportation
systems in lieu of using the Partnerships. The
Partnerships ability to renew or replace existing
contracts with its customers at rates sufficient to maintain
current revenues and cash flows could be adversely affected by
the activities of its competitors and its customers. All of
these competitive pressures could have a material adverse effect
on the Partnerships business, results of operations, and
financial condition.

The
Partnership typically does not obtain independent evaluations of
natural gas reserves dedicated to its gathering pipeline
systems; therefore, volumes of natural gas on the
Partnerships systems in the future could be less than it
anticipates.

The Partnership typically does not obtain independent
evaluations of natural gas reserves connected to its gathering
systems due to the unwillingness of producers to provide reserve
information as well as the cost of such evaluations.
Accordingly, the Partnership does not have independent estimates
of total reserves dedicated to its gathering systems or the
anticipated life of such reserves. If the total reserves or
estimated life of the reserves connected to its gathering
systems is less than it anticipates and the Partnership is
unable to secure additional sources of natural gas, then the
volumes of natural gas transported on its gathering systems in
the future could be less than it anticipates. A decline in the
volumes of natural gas on the Partnerships systems could
have a material adverse effect on its business, results of
operations, and financial condition.

A reduction in
demand for NGL products by the petrochemical, refining or other
industries or by the fuel markets, or a significant increase in
NGL product supply relative to this demand, could materially
adversely affect the Partnerships business, results of
operations and financial condition.

The NGL products the Partnership produces have a variety of
applications, including as heating fuels, petrochemical
feedstocks and refining blend stocks. A reduction in demand for
NGL products, whether because of general or industry specific
economic conditions, new government regulations, global
competition, reduced demand by consumers for products made with
NGL products (for example; reduced petrochemical demand observed
due to lower activity in the automobile and construction
industries), increased competition from petroleum-based
feedstocks due to pricing differences, mild winter weather for
some NGL applications or other reasons, could result in a
decline in the volume of NGL products the Partnership handles or
reduce the fees it charges for its services. Also, increased
supply of NGL products

could reduce the value of NGLs handled by the Partnership and
reduce the margins realized. The Partnerships NGL products
and their demand are affected as follows:

Ethane. Ethane is typically supplied as purity
ethane and as part of ethane-propane mix. Ethane is primarily
used in the petrochemical industry as feedstock for ethylene,
one of the basic building blocks for a wide range of plastics
and other chemical products. Although ethane is typically
extracted as part of the mixed NGL stream at gas processing
plants, if natural gas prices increase significantly in relation
to NGL product prices or if the demand for ethylene falls, it
may be more profitable for natural gas processors to leave the
ethane in the natural gas stream thereby reducing the volume of
NGLs delivered for fractionation and marketing.

Propane. Propane is used as a petrochemical
feedstock in the production of ethylene and propylene, as a
heating, engine and industrial fuel, and in agricultural
applications such as crop drying. Changes in demand for ethylene
and propylene could adversely affect demand for propane. The
demand for propane as a heating fuel is significantly affected
by weather conditions. The volume of propane sold is at its
highest during the six-month peak heating season of October
through March. Demand for the Partnerships propane may be
reduced during periods of
warmer-than-normal
weather.

Normal Butane. Normal butane is used in the
production of isobutane, as a refined product blending
component, as a fuel gas, and in the production of ethylene and
propylene. Changes in the composition of refined products
resulting from governmental regulation, changes in feedstocks,
products and economics, demand for heating fuel and for ethylene
and propylene could adversely affect demand for normal butane.

Isobutane. Isobutane is predominantly used in
refineries to produce alkylates to enhance octane levels.
Accordingly, any action that reduces demand for motor gasoline
or demand for isobutane to produce alkylates for octane
enhancement might reduce demand for isobutane.

Natural Gasoline. Natural gasoline is used as
a blending component for certain refined products and as a
feedstock used in the production of ethylene and propylene.
Changes in the mandated composition resulting from governmental
regulation of motor gasoline and in demand for ethylene and
propylene could adversely affect demand for natural gasoline.

NGLs and products produced from NGLs also compete with global
markets. Any reduced demand or increased supply for ethane,
propane, normal butane, isobutane or natural gasoline in the
markets the Partnerships accesses for any of the reasons
stated above could adversely affect demand for the services it
provides as well as NGL prices, which would negatively impact
the Partnerships results of operations and financial
condition.

The
Partnership has significant relationships with ChevronPhillips
Chemical Company LP as a customer for its marketing and refinery
services. In some cases, these agreements are subject to
renegotiation and termination rights.

For the nine months ended September 30, 2010 and the year
ended December 31, 2009, approximately 12% and 16% of the
Partnerships consolidated revenues were derived from
transactions with CPC. Under many of the Partnerships CPC
contracts where it purchases or markets NGLs on CPCs
behalf, CPC may elect to terminate the contracts or renegotiate
the price terms. To the extent CPC reduces the volumes of NGLs
that it purchases from the Partnership or reduces the volumes of
NGLs that the Partnership markets on its behalf, or to the
extent the economic terms of such contracts are changed, the
Partnerships revenues and cash available for debt service
could decline.

The tax
treatment of the Partnership depends on its status as a
partnership for federal income tax purposes as well as its not
being subject to a material amount of entity-level taxation by
individual states. If the Internal Revenue Service
(IRS) were to treat the

Partnership as a corporation for federal income tax
purposes or the Partnership becomes subject to a material amount
of entity-level taxation for state tax purposes, then its cash
available for distribution to its unitholders, including us,
would be substantially reduced.

We currently own an approximate 15% limited partner interest, a
2% general partner interest and the IDRs in the Partnership. The
anticipated after-tax economic benefit of our investment in the
Partnership depends largely on its being treated as a
partnership for federal income tax purposes. In order to
maintain its status as a partnership for United States federal
income tax purposes, 90 percent or more of the gross income
of the Partnership for every taxable year must be
qualifying income under section 7704 of
the Internal Revenue Code of 1986, as amended. The Partnership
has not requested and does not plan to request a ruling from the
IRS with respect to its treatment as a partnership for federal
income tax purposes.

Despite the fact that the Partnership is a limited partnership
under Delaware law, it is possible, under certain circumstances
for an entity such as the Partnership to be treated as a
corporation for federal income tax purposes. Although the
Partnership does not believe based upon its current operations
that it is so treated, a change in the Partnerships
business could cause it to be treated as a corporation for
federal income tax purposes or otherwise subject it to federal
income taxation as an entity.

If the Partnership were treated as a corporation for federal
income tax purposes, it would pay federal income tax on its
taxable income at the corporate tax rate, which is currently a
maximum of 35%, and would likely pay state income tax at varying
rates. Distributions to the Partnerships unitholders,
including us, would generally be taxed again as corporate
distributions and no income, gains, losses or deductions would
flow through to the Partnerships unitholders, including
us. If such tax was imposed upon the Partnership as a
corporation, its cash available for distribution would be
substantially reduced. Therefore, treatment of the Partnership
as a corporation would result in a material reduction in the
anticipated cash flow and after-tax return to the
Partnerships unitholders, including us, and would likely
cause a substantial reduction in the value of our investment in
the Partnership.

In addition, current law may change so as to cause the
Partnership to be treated as a corporation for federal income
tax purposes or otherwise subject the Partnership to
entity-level taxation for state or local income tax purposes. At
the federal level, members of Congress have recently considered
legislative changes that would affect the tax treatment of
certain publicly traded partnerships. Although the considered
legislation would not appear to have affected the
Partnerships treatment as a partnership, we are unable to
predict whether any of these changes, or other proposals will be
reintroduced or will ultimately be enacted. Moreover, any
modification to the federal income tax laws and interpretations
thereof may or may not be applied retroactively. Any such
changes could negatively impact the value of an investment in
the Partnerships common units. At the state level, because
of widespread state budget deficits and other reasons, several
states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income,
franchise and other forms of taxation. For example, the
Partnership is required to pay Texas franchise tax at a maximum
effective rate of 0.7% of its gross income apportioned to Texas
in the prior year. Imposition of any similar tax on the
Partnership by additional states would reduce the cash available
for distribution to Partnership unitholders, including us.

The Partnerships partnership agreement provides that if a
law is enacted or existing law is modified or interpreted in a
manner that subjects it to taxation as a corporation or
otherwise subjects it to entity-level taxation for federal,
state or local income tax purposes, the minimum quarterly
distribution and the target distribution amounts may be adjusted
to reflect the impact of that law on the Partnership.

The
Partnership does not own most of the land on which its pipelines
and compression facilities are located, which could disrupt its
operations.

The Partnership does not own most of the land on which its
pipelines and compression facilities are located, and the
Partnership is therefore subject to the possibility of more
onerous terms
and/or
increased costs to retain necessary land use if it does not have
valid
rights-of-way
or leases or if such
rights-of-way
or leases lapse or terminate. The Partnership sometimes obtains
the rights to land owned by third parties and governmental
agencies for a specific period of time. The Partnerships
loss of these rights, through its

inability to renew
right-of-way
contracts, leases or otherwise, could cause it to cease
operations on the affected land, increase costs related to
continuing operations elsewhere, and reduce its revenue.

The
Partnership may be unable to cause its majority-owned joint
ventures to take or not to take certain actions unless some or
all of its joint venture participants agree.

The Partnership participates in several majority-owned joint
ventures whose corporate governance structures require at least
a majority in interest vote to authorize many basic activities
and require a greater voting interest (sometimes up to 100%) to
authorize more significant activities. Examples of these more
significant activities are large expenditures or contractual
commitments, the construction or acquisition of assets,
borrowing money or otherwise raising capital, making
distributions, transactions with affiliates of a joint venture
participant, litigation and transactions not in the ordinary
course of business, among others. Without the concurrence of
joint venture participants with enough voting interests, the
Partnership may be unable to cause any of its joint ventures to
take or not take certain actions, even though taking or
preventing those actions may be in the best interest of the
Partnership or the particular joint venture.

In addition, subject to certain conditions, any joint venture
owner may sell, transfer or otherwise modify its ownership
interest in a joint venture, whether in a transaction involving
third parties or the other joint owners. Any such transaction
could result in the Partnership partnering with different or
additional parties.

Weather may
limit the Partnerships ability to operate its business and
could adversely affect its operating results.

The weather in the areas in which the Partnership operates can
cause disruptions and in some cases suspension of its
operations. For example, unseasonably wet weather, extended
periods of below-freezing weather and hurricanes may cause
disruptions or suspensions of the Partnerships operations,
which could adversely affect its operating results.

The Partnerships business involves many hazards and
operational risks, some of which may not be insured or fully
covered by insurance. If a significant accident or event occurs
that is not fully insured, if the Partnership fails to recover
all anticipated insurance proceeds for significant accidents or
events for which it is insured, or if it fails to rebuild
facilities damaged by such accidents or events, its operations
and financial results could be adversely affected.

The Partnerships operations are subject to many hazards
inherent in the gathering, compressing, treating, processing and
transporting of natural gas and the fractionation, storage and
transportation of NGLs, including:



damage to pipelines and plants, related equipment and
surrounding properties caused by hurricanes, tornadoes, floods,
fires and other natural disasters, explosions and acts of
terrorism;



inadvertent damage from third parties, including from
construction, farm and utility equipment;



leaks of natural gas, NGLs and other hydrocarbons or losses of
natural gas or NGLs as a result of the malfunction of equipment
or facilities; and



other hazards that could also result in personal injury and loss
of life, pollution and suspension of operations.

These risks could result in substantial losses due to personal
injury, loss of life, severe damage to and destruction of
property and equipment and pollution or other environmental
damage and may result in curtailment or suspension of the
Partnerships related operations. A natural disaster or
other hazard affecting the areas in which the Partnership
operates could have a material adverse effect on its operations.
For example, Hurricanes Katrina and Rita damaged gathering
systems, processing facilities, NGL fractionators and pipelines
along the Gulf Coast, including certain of the
Partnerships facilities. These hurricanes disrupted the
operations of the Partnerships customers in August and
September 2005, which curtailed or suspended the operations of
various energy companies with assets in the region. The
Louisiana

and Texas Gulf Coast was similarly impacted in September 2008 as
a result of Hurricanes Gustav and Ike. The Partnership is not
fully insured against all risks inherent to its business. The
Partnership is not insured against all environmental accidents
that might occur which may include toxic tort claims, other than
incidents considered to be sudden and accidental. If a
significant accident or event occurs that is not fully insured,
if the Partnership fails to recover all anticipated insurance
proceeds for significant accidents or events for which it is
insured, or if it fails to rebuild facilities damaged by such
accidents or events, its operations and financial condition
could be adversely affected. In addition, the Partnership may
not be able to maintain or obtain insurance of the type and
amount it desires at reasonable rates. As a result of market
conditions, premiums and deductibles for certain of the
Partnerships insurance policies have increased
substantially, and could escalate further. For example,
following Hurricanes Katrina and Rita, insurance premiums,
deductibles and co-insurance requirements increased
substantially, and terms were generally less favorable than
terms that could be obtained prior to such hurricanes. Insurance
market conditions worsened as a result of the losses sustained
from Hurricanes Gustav and Ike in September 2008. As a result,
the Partnership experienced further increases in deductibles and
premiums, and further reductions in coverage and limits, with
some coverages unavailable at any cost.

The
Partnership may incur significant costs and liabilities
resulting from pipeline integrity programs and related
repairs.

Pursuant to the Pipeline Safety Improvement Act of 2002, as
reauthorized and amended by the Pipeline Inspection, Protection,
Enforcement and Safety Act of 2006, the DOT, through the PHMSA,
has adopted regulations requiring pipeline operators to develop
integrity management programs for transmission pipelines located
where a leak or rupture could do the most harm in high
consequence areas, including high population areas, areas
that are sources of drinking water, ecological resource areas
that are unusually sensitive to environmental damage from a
pipeline release and commercially navigable waterways, unless
the operator effectively demonstrates by risk assessment that
the pipeline could not affect the area. The regulations require
operators of covered pipelines to:



perform ongoing assessments of pipeline integrity;



identify and characterize applicable threats to pipeline
segments that could impact a high consequence area;



improve data collection, integration and analysis;



repair and remediate the pipeline as necessary; and



implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing
DOT regulations for intrastate gathering and transmission lines.
The Partnership currently estimates that it will incur an
aggregate cost of approximately $5.1 million between 2010
and 2012 to implement pipeline integrity management program
testing along certain segments of its natural gas and NGL
pipelines. This estimate does not include the costs, if any, of
any repair, remediation, preventative or mitigating actions that
may be determined to be necessary as a result of the testing
program, which costs could be substantial. At this time, the
Partnership cannot predict the ultimate cost of compliance with
this regulation, as the cost will vary significantly depending
on the number and extent of any repairs found to be necessary as
a result of the pipeline integrity testing. Following the
initial round of testing and repairs, the Partnership will
continue its pipeline integrity testing programs to assess and
maintain the integrity of its pipelines. The results of these
tests could cause the Partnership to incur significant and
unanticipated capital and operating expenditures for repairs or
upgrades deemed necessary to ensure the continued safe and
reliable operations of its pipelines.

Unexpected
volume changes due to production variability or to gathering,
plant or pipeline system disruptions may increase the
Partnerships exposure to commodity price
movements.

The Partnership sells processed natural gas to third parties at
plant tailgates or at pipeline pooling points. Sales made to
natural gas marketers and end-users may be interrupted by
disruptions to volumes anywhere along the system. The
Partnership attempts to balance sales with volumes supplied from
processing operations, but unexpected volume variations due to
production variability or to gathering, plant or pipeline system
disruptions may expose the Partnership to volume imbalances
which, in conjunction with movements in commodity prices, could
materially impact the Partnerships income from operations
and cash flow.

The
Partnership requires a significant amount of cash to service its
indebtedness. The Partnerships ability to generate cash
depends on many factors beyond its control.

The Partnerships ability to make payments on and to
refinance its indebtedness and to fund planned capital
expenditures depends on its ability to generate cash in the
future. This, to a certain extent, is subject to general
economic, financial, competitive, legislative, regulatory and
other factors that are beyond its control. We cannot assure you
that the Partnership will generate sufficient cash flow from
operations or that future borrowings will be available to it
under its credit agreement or otherwise in an amount sufficient
to enable it to pay its indebtedness or to fund its other
liquidity needs. The Partnership may need to refinance all or a
portion of its indebtedness at or before maturity. The
Partnership cannot assure you that it will be able to refinance
any of its indebtedness on commercially reasonable terms or at
all.

Failure to
comply with existing or new environmental laws or regulations or
an accidental release of hazardous substances, hydrocarbons or
wastes into the environment may cause the Partnership to incur
significant costs and liabilities.

The Partnerships operations are subject to stringent and
complex federal, state and local environmental laws and
regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection.
These laws include, for example, (1) the federal Clean Air
Act and comparable state laws that impose obligations related to
air emissions, (2) the Federal Resource Conservation and
Recovery Act, as amended, (RCRA) and comparable
state laws that impose obligations for the handling, storage,
treatment or disposal of solid and hazardous waste from the
Partnerships facilities, (3) the Federal
Comprehensive Environmental Response, Compensation and Liability
Act of 1980, as amended, (CERCLA or the
Superfund law) and comparable state laws that
regulate the cleanup of hazardous substances that may have been
released at properties currently or previously owned or operated
by us or at locations to which the Partnerships hazardous
substances have been transported for recycling or disposal and
(4) the Clean Water Act and comparable state laws that
regulate discharges of wastewater from the Partnerships
facilities to state and federal waters. Failure to comply with
these laws and regulations or newly adopted laws or regulations
may trigger a variety of administrative, civil and criminal
enforcement measures, including the assessment of monetary
penalties or other sanctions, the imposition of remedial
obligations and the issuance of orders enjoining future
operations or imposing additional compliance requirements on
such operations. Certain environmental laws, including CERCLA
and analogous state laws, impose strict, joint and several
liability for costs required to clean up and restore sites where
hazardous substances, hydrocarbons or wastes have been disposed
or otherwise released. Moreover, it is not uncommon for
neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by
noise, odor or the release of hazardous substances, hydrocarbons
or wastes into the environment.

There is inherent risk of incurring environmental costs and
liabilities in connection with the Partnerships operations
due to its handling of natural gas, NGLs and other petroleum
products, because of air emissions and water discharges related
to its operations, and as a result of historical industry
operations and waste disposal practices. For example, an
accidental release from one of the Partnerships facilities
could subject it to substantial liabilities arising from
environmental cleanup and

restoration costs, claims made by neighboring landowners and
other third parties for personal injury, natural resource and
property damages and fines or penalties for related violations
of environmental laws or regulations.

Moreover, stricter laws, regulations or enforcement policies
could significantly increase the Partnerships operational
or compliance costs and the cost of any remediation that may
become necessary. For instance, since August 2009, the Texas
Commission on Environmental Quality has conducted a series of
analyses of air emissions in the Barnett Shale area in response
to reported concerns about high concentrations of benzene in the
air near drilling sites and natural gas processing facilities,
and the analysis could result in the adoption of new air
emission regulatory or permitting limitations that could require
the Partnership to incur increased capital or operating costs.
The Partnership is also conducting its own evaluation of air
emissions at certain of its facilities in the Barnett Shale area
and, as necessary, plans to conduct corrective actions at such
facilities. Additionally, environmental groups have advocated
increased regulation and a moratorium on the issuance of
drilling permits for new natural gas wells in the Barnett Shale
area. The adoption of any laws, regulations or other legally
enforceable mandates that result in more stringent air emission
limitations or that restrict or prohibit the drilling of new
natural gas wells for any extended period of time could increase
the Partnerships operating and compliance costs as well as
reduce the rate of production of natural gas operators with whom
the Partnership has a business relationship, which could have a
material adverse effect on the Partnerships results of
operations and cash flows. The Partnership may not be able to
recover some or any of these costs from insurance.

Increased
regulation of hydraulic fracturing could result in reductions or
delays in drilling and completing new oil and natural gas wells,
which could adversely impact the Partnerships revenues by
decreasing the volumes of natural gas that the Partnership
gathers, processes and fractionates.

Hydraulic fracturing is a process used by oil and gas
exploration and production operators in the completion of
certain oil and gas wells whereby water, sand and chemicals are
injected under pressure into subsurface formations to stimulate
gas and, to a lesser extent, oil production. Due to concerns
that hydraulic fracturing may adversely affect drinking water
supplies, the U.S. Environmental Protection Agency
(EPA) recently announced its plan to conduct a
comprehensive research study to investigate the potential
adverse impact that hydraulic fracturing may have on water
quality and public health. The initial study results are
expected to be available in late 2012. Additionally, legislation
has been introduced in the U.S. Congress to amend the
federal Safe Drinking Water Act to subject hydraulic fracturing
operations to regulation under that Act and to require the
disclosure of chemicals used by the oil and gas industry in the
hydraulic fracturing process. If enacted, such a provision could
require hydraulic fracturing activities to meet permitting and
financial assurance requirements, adhere to certain construction
specifications, fulfill monitoring, reporting and recordkeeping
requirements and meet plugging and abandonment requirements. In
unrelated oil spill legislation being considered by the
U.S. Senate in the aftermath of the April 2010 Macondo well
release in the Gulf of Mexico, an amending provision has been
prepared that would require natural gas drillers to disclose the
chemicals they pump into the ground as part of the hydraulic
fracturing process. Disclosure of chemicals used in the
fracturing process could make it easier for third parties
opposing hydraulic fracturing to initiate legal proceedings
based on allegations that specific chemicals used in the
fracturing process could adversely affect groundwater. Adoption
of legislation or of any implementing regulations placing
restrictions on hydraulic fracturing activities could impose
operational delays, increased operating costs and additional
regulatory burdens on exploration and production operators,
which could reduce their production of natural gas and, in turn,
adversely affect the Partnerships revenues and results of
operations by decreasing the volumes of natural gas that it
gathers, processes and fractionates.

A change in
the jurisdictional characterization of some of the
Partnerships assets by federal, state or local regulatory
agencies or a change in policy by those agencies may result in
increased regulation of the Partnerships assets, which may
cause its revenues to decline and operating expenses to
increase.

Venice Gathering System, L.L.C. (VGS) is a wholly
owned subsidiary of VESCO engaged in the business of
transporting natural gas in interstate commerce, under
authorization granted by and subject to the jurisdiction of the
Federal Energy Regulatory Commission (FERC) under
the Natural Gas Act of 1938 (NGA). VGS owns and
operates a natural gas gathering system extending from South
Timbalier Block 135 to an onshore interconnection to a
natural gas processing plant owned by VESCO. With the exception
of our interest in VGS, our operations are generally exempt from
FERC regulation under the NGA, but FERC regulation still affects
our non-FERC jurisdictional businesses and the markets for
products derived from these businesses. The NGA exempts natural
gas gathering facilities from regulation by FERC as a natural
gas company under the NGA. The Partnership believes that the
natural gas pipelines in its gathering systems meet the
traditional tests FERC has used to establish a pipelines
status as a gatherer not subject to regulation as a natural gas
company. However, the distinction between FERC-regulated
transmission services and federally unregulated gathering
services is the subject of substantial,
on-going
litigation, so the classification and regulation of the
Partnerships gathering facilities are subject to change
based on future determinations by FERC, the courts or Congress.
In addition, the courts have determined that certain pipelines
that would otherwise be subject to the ICA are exempt from
regulation by FERC under the ICA as proprietary lines. The
classification of a line as a proprietary line is a fact-based
determination subject to FERC and court review. Accordingly, the
classification and regulation of some of the Partnerships
gathering facilities and transportation pipelines may be subject
to change based on future determinations by FERC, the courts, or
Congress.

While the Partnerships natural gas gathering operations
are generally exempt from FERC regulation under the NGA, its gas
gathering operations may be subject to certain FERC reporting
and posting requirements in a given year. FERC has issued a
final rule (as amended by orders on rehearing and
clarification), Order 704, requiring certain participants
in the natural gas market, including intrastate pipelines,
natural gas gatherers, natural gas marketers and natural gas
processors, that engage in a minimum level of natural gas sales
or purchases to submit annual reports regarding those
transactions to FERC. In June 2010, FERC issued an Order
granting clarification regarding Order 704.

In addition, FERC has issued a final rule, (as amended by orders
on rehearing and clarification), Order 720, requiring major
non-interstate pipelines, defined as certain non-interstate
pipelines delivering, on an annual basis, more than an average
of 50 million MMBtus of gas over the previous three
calendar years, to post daily certain information regarding the
pipelines capacity and scheduled flows for each receipt
and delivery point that has design capacity equal to or greater
than 15,000 MMBtu/d and requiring interstate pipelines to
post information regarding the provision of no-notice service.
The Partnership takes the position that at this time Targa
Louisiana Intrastate LLC is exempt from this rule.

In addition, FERC recently issued an order extending certain of
the open-access requirements including the prohibition on
buy/sell arrangements and shipper-must-have-title provisions to
include Hinshaw pipelines to the extent such pipelines provide
interstate service. However, FERC issued a Notice of Inquiry on
October 21, 2010, effectively suspending the recent ruling
and requesting comments on whether and how holders of firm
capacity on Section 311 and Hinshaw pipelines should be
permitted to allow others to make use of their firm interstate
capacity, including to what extent buy/sell transactions should
be permitted. We have no way to predict with certainty whether
and to what extent the buy/sell prohibition and
shipper-must-have title provisions will be modified in response
to the Notice of Inquiry.

Other FERC regulations may indirectly impact the
Partnerships businesses and the markets for products
derived from these businesses. FERCs policies and
practices across the range of its natural gas regulatory
activities, including, for example, its policies on open access
transportation, gas quality, ratemaking, capacity release and
market center promotion, may indirectly affect the intrastate
natural gas market. In recent years, FERC has pursued
pro-competitive policies in its regulation of interstate natural

gas pipelines. However, we cannot assure you that FERC will
continue this approach as it considers matters such as pipeline
rates and rules and policies that may affect rights of access to
transportation capacity.

Should the
Partnership fail to comply with all applicable FERC administered
statutes, rules, regulations and orders, it could be subject to
substantial penalties and fines.

Under the Domenici-Barton Energy Policy Act of 2005 (EP
Act 2005), which is applicable to VGS, FERC has civil
penalty authority under the NGA to impose penalties for current
violations of up to $1 million per day for each violation
and disgorgement of profits associated with any violation. While
the Partnerships systems have not been regulated by FERC
as a natural gas companies under the NGA, FERC has adopted
regulations that may subject certain of its otherwise non-FERC
jurisdictional facilities to FERC annual reporting and daily
scheduled flow and capacity posting requirements. Additional
rules and legislation pertaining to those and other matters may
be considered or adopted by FERC from time to time. Failure to
comply with those regulations in the future could subject the
Partnership to civil penalty liability.

Climate change
legislation and regulatory initiatives could result in increased
operating costs and reduced demand for the natural gas and NGL
services the Partnership provides.

On December 15, 2009, the EPA published its findings that
emissions of carbon dioxide, methane and other greenhouse gases
(GHGs) present an endangerment to public health and
the environment because emissions of such gases are, according
to the EPA, contributing to warming of the earths
atmosphere and other climatic changes. These findings allow the
EPA to proceed with the adoption and implementation of
regulations restricting emissions of GHGs under existing
provisions of the federal Clean Air Act. Accordingly, the EPA
has adopted two sets of regulations under the Clean Air Act that
would require a reduction in emissions of GHGs from motor
vehicles and could trigger permit review for GHG emissions from
certain stationary sources. Moreover, on October 30, 2009,
the EPA published a Mandatory Reporting of Greenhouse
Gases final rule that establishes a new comprehensive
scheme requiring operators of stationary sources emitting more
than established annual thresholds of carbon dioxide-equivalent
GHGs to inventory and report their GHG emissions annually on a
facility-by-facility
basis. On November 8, 2010, the EPA adopted amendments to
this GHG reporting rule, expanding the monitoring and reporting
obligations to include onshore and offshore oil and natural gas
production facilities and onshore oil and natural gas
processing, transmission, storage and distribution facilities,
beginning in 2012 for emissions occurring in 2011.

In addition, both houses of Congress have actively considered
legislation to reduce emissions of GHGs, and almost half of the
states have already taken legal measures to reduce emissions of
GHGs, primarily through the planned development of GHG emission
inventories
and/or
regional GHG cap and trade programs. Most of these cap and trade
programs work by requiring either major sources of emissions,
such as electric power plants, or major producers of fuels, such
as refineries and NGL fractionation plants, to acquire and
surrender emission allowances with the number of allowances
available for purchase is reduced each year until the overall
GHG emission reduction goal is achieved. The adoption of
legislation or regulations imposing reporting or permitting
obligations on, or limiting emissions of GHGs from, the
Partnerships equipment and operations could require it to
incur additional costs to reduce emissions of GHGs associated
with its operations, could adversely affect its performance of
operations in the absence of any permits that may be required to
regulate emission of greenhouse gases, or could adversely affect
demand for the natural gas it gathers, treats or otherwise
handles in connection with its services.

The recent
adoption of derivatives legislation by the United States
Congress could have an adverse effect on the Partnerships
ability to hedge risks associated with its
business.

The United States Congress recently adopted comprehensive
financial reform legislation that establishes federal oversight
and regulation of the
over-the-counter
derivatives market and entities, such as the Partnership, that
participate in that market. The new legislation was signed into
law by the President on July 21, 2010, and requires the
Commodities Futures Trading Commission (the CFTC)
and the SEC to promulgate rules and regulations implementing the
new legislation within 360 days from the date of

enactment. The CFTC has also proposed regulations to set
position limits for certain futures and option contracts in the
major energy markets, although it is not possible at this time
to predict whether or when the CFTC will adopt those rules or
include comparable provisions in its rulemaking under the new
legislation. The financial reform legislation may also require
the Partnership to comply with margin requirements in connection
with its derivative activities, although the application of
those provisions to the Partnership is uncertain at this time.
The financial reform legislation also requires many
counterparties to the Partnerships derivative instruments
to spin off some of their derivatives activities to a separate
entity, which may not be as creditworthy as the current
counterparty. The new legislation and any new regulations could
significantly increase the cost of derivative contracts
(including those requirements to post collateral which could
adversely affect the Partnerships available liquidity),
materially alter the terms of derivative contracts, reduce the
availability of derivatives to protect against risks the
Partnership encounters, reduce the Partnerships ability to
monetize or restructure its existing derivative contracts, and
increase the Partnerships exposure to less creditworthy
counterparties. If the Partnership reduces its use of
derivatives as a result of the legislation and regulations, its
results of operations may become more volatile and its cash
flows may be less predictable, which could adversely affect its
ability to plan for and fund capital expenditures. Finally, the
legislation was intended, in part, to reduce the volatility of
oil and natural gas prices, which some legislators attributed to
speculative trading in derivatives and commodity instruments
related to oil and natural gas. The Partnerships revenues
could therefore be adversely affected if a consequence of the
legislation and regulations is to lower commodity prices. Any of
these consequences could have a material adverse effect on the
Partnership, its financial condition, and its results of
operations.

The
Partnerships interstate common carrier liquids pipeline is
regulated by the Federal Energy Regulatory
Commission.

Targa NGL Pipeline Company LLC (Targa NGL), one of
the Partnerships subsidiaries, is an interstate NGL common
carrier subject to regulation by the FERC under the ICA. Targa
NGL owns a twelve inch diameter pipeline that runs between Lake
Charles, Louisiana and Mont Belvieu, Texas. This pipeline can
move mixed NGL and purity NGL products. Targa NGL also owns an
eight inch diameter pipeline and a 20 inch diameter
pipeline each of which run between Mont Belvieu, Texas and
Galena Park, Texas. The eight inch and the 20 inch
pipelines are part of an extensive mixed NGL and purity NGL
pipeline receipt and delivery system that provides services to
domestic and foreign import and export customers. The Interstate
Commerce Act (ICA) requires that the Partnership
maintain tariffs on file with FERC for each of these pipelines.
Those tariffs set forth the rates the Partnership charges for
providing transportation services as well as the rules and
regulations governing these services. The ICA requires, among
other things, that rates on interstate common carrier pipelines
be just and reasonable and non-discriminatory. All
shippers on these pipelines are the Partnerships
subsidiaries.

Recent events
in the Gulf of Mexico may adversely affect the operations of the
Partnership.

On April 20, 2010, the Transocean Deepwater Horizon
drilling rig exploded and subsequently sank 130 miles south
of New Orleans, Louisiana, and the resulting release of crude
oil into the Gulf of Mexico was declared a Spill of National
Significance by the United States Department of Homeland
Security. The Partnership cannot predict with any certainty the
impact of this oil spill, the extent of cleanup activities
associated with this spill, or possible changes in laws or
regulations that may be enacted in response to this spill, but
this event and its aftermath could adversely affect the
Partnerships operations. It is possible that the direct
results of the spill and clean-up efforts could interrupt
certain offshore production processed by our facilities.
Furthermore, additional governmental regulation of, or delays in
issuance of permits for, the offshore exploration and production
industry may negatively impact current or future volumes being
gathered or processed by the Partnerships facilities, and
may potentially reduce volumes in its downstream logistics and
marketing business.

Terrorist
attacks and the threat of terrorist attacks have resulted in
increased costs to the Partnerships business. Continued
hostilities in the Middle East or other sustained military
campaigns may adversely impact the Partnerships results of
operations.

The long-term impact of terrorist attacks, such as the attacks
that occurred on September 11, 2001, and the threat of
future terrorist attacks on the Partnerships industry in
general and on it in particular is not known at this time.
However, resulting regulatory requirements
and/or
related business decisions associated with security are likely
to increase the Partnerships costs.

Increased security measures taken by the Partnership as a
precaution against possible terrorist attacks have resulted in
increased costs to its business. Uncertainty surrounding
continued hostilities in the Middle East or other sustained
military campaigns may affect the Partnerships operations
in unpredictable ways, including disruptions of crude oil
supplies and markets for its products, and the possibility that
infrastructure facilities could be direct targets, or indirect
casualties, of an act of terror.

Changes in the insurance markets attributable to terrorist
attacks may make certain types of insurance more difficult for
the Partnership to obtain. Moreover, the insurance that may be
available to the Partnership may be significantly more expensive
than its existing insurance coverage. Instability in the
financial markets as a result of terrorism or war could also
affect the Partnerships ability to raise capital.

We will not receive any of the net proceeds from any sale of
shares of common stock by any selling stockholder. We expect to
incur approximately $2.5 million of expenses in connection
with this offering, including all expenses of the selling
stockholders which we have agreed to pay and a structuring fee
of approximately $687,500 to be paid to Barclays Capital Inc.
for evaluation, structuring and analysis in connection with the
offering.

The following table sets forth our cash and cash equivalents and
capitalization as of September 30, 2010,



on an actual basis;



on an as adjusted basis to give effect to the repayment of
$141.3 million of face value of indebtedness under the
Holdco Loan for $137.4 million and the $18 million
repayment of the accreted value of the Series B Preferred
included in our September 30, 2010 balance sheet; and



on an as further adjusted basis to give effect to the
transactions described under SummaryOur Structure
and Ownership After This Offering.

You should read the following table in conjunction with
Selected Historical Financial and Operating Data,
Managements Discussion and Analysis of Financial
Condition and Results of Operations and our historical
consolidated financial statements and related notes thereto
appearing elsewhere in this prospectus.

Actual

As Adjusted

9/30/10

As Adjusted

For Offering

($ in millions)

Cash & Cash
Equivalents(1)

$

350.0

$

194.6

$

188.3

Debt:

Our Obligations:

Holdco Loan, due February 2015

$

230.2

$

88.9

$

88.9

TRI Senior secured revolving credit facility, due July
2014(2)







TRI Senior secured term loan facility, due July 2016







Unamortized discounts, net of premiums







Obligations of the Partnership:

Senior secured revolving credit facility, due July 2015

753.3

753.3

753.3

81/4% Senior
unsecured notes, due July 2016

209.1

209.1

209.1

111/4% Senior
unsecured notes, due July 2017

231.3

231.3

231.3

77/8% Senior
unsecured notes, due October 2018

250.0

250.0

250.0

Unamortized discounts, net of premiums

(10.5

)

(10.5

)

(10.5

)

Total Debt

1,663.4

1,522.1

1,522.1

Series B preferred stock

96.8

78.8



Targa Resources Corp. stockholders equity

58.8

62.8

134.3

Noncontrolling interest in subsidiaries

935.5

935.5

935.5

Total Capitalization

$

2,754.5

$

2,599.2

$

2,591.9

(1)

At closing we expect to have
sufficient cash to satisfy certain tax, capital expenditure, and
other obligations. See Managements Discussion and
Analysis of Financial Condition and Results of
OperationsLiquidity and Capital Resources.

(2)

In conjunction with the sale of our
interests in Versado to the Partnership, the revolving credit
facility commitment was reduced to $75 million.

We intend to pay to our stockholders, on a quarterly basis,
dividends equal to the cash we receive from our Partnership
distributions, less reserves for expenses, future dividends and
other uses of cash, including:



Federal income taxes, which we are required to pay because we
are taxed as a corporation;



the expenses of being a public company;



other general and administrative expenses;



general and administrative reimbursements to the Partnership;



capital contributions to the Partnership upon the issuance by it
of additional partnership securities if we choose to maintain
the General Partners 2.0% interest;



reserves our board of directors believes prudent to maintain;



our obligation to (i) satisfy tax obligations associated
with previous sales of assets to the Partnership,
(ii) reimburse the Partnership for certain capital
expenditures related to Versado and (iii) provide the
Partnership with limited quarterly distribution support through
2011, all as described in more detail in Managements
Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital Resources; and



interest expense or principal payments on any indebtedness we
incur.

Based on the current distribution policy of the Partnership,
expected cash to be received from the Partnership, our expected
federal income tax liabilities, our expected level of other
expenses and reserves that our board of directors believes
prudent to maintain, we expect that our initial quarterly
dividend rate will be $0.2575 per share. If the Partnership is
successful in implementing its business strategy and increasing
distributions to its partners, we would generally expect to
increase dividends to our stockholders, although the timing and
amount of any such increased dividends will not necessarily be
comparable to the increased Partnership distributions. We expect
to pay a pro rated dividend for the portion of the fourth
quarter of 2010 that we are public in February 2011. However, we
cannot assure you that any dividends will be declared or paid.

The determination of the amount of cash dividends, including the
quarterly dividend referred to above, if any, to be declared and
paid will depend upon our financial condition, results of
operations, cash flow, the level of our capital expenditures,
future business prospects and any other matters that our board
of directors deems relevant. The Partnerships debt
agreements contain restrictions on the payment of distributions
and prohibit the payment of distributions if the Partnership is
in default. If the Partnership cannot make incentive
distributions to the general partner or limited partner
distributions to us, we will be unable to pay dividends on our
common stock.

The
Partnerships Cash Distribution Policy

Under the Partnerships partnership agreement, available
cash is defined to generally mean, for each fiscal quarter, all
cash on hand at the date of determination of available cash for
that quarter less the amount of cash reserves established by the
General Partner to provide for the proper conduct of the
Partnerships business, to comply with applicable law or
any agreement binding on the Partnership and its subsidiaries
and to provide for future distributions to the
Partnerships unitholders for any one or more of the
upcoming four quarters. The determination of available cash
takes into account the possibility of establishing cash reserves
in some quarterly periods that the Partnership may use to pay
cash distributions in other quarterly periods, thereby enabling
it to maintain relatively consistent cash distribution levels
even if the Partnerships business experiences fluctuations
in its cash from operations due to seasonal and cyclical
factors. The General Partners determination of available
cash also allows the Partnership to maintain

reserves to provide funding for its growth opportunities. The
Partnership makes its quarterly distributions from cash
generated from its operations, and those distributions have
grown over time as its business has grown, primarily as a result
of numerous acquisitions and organic expansion projects that
have been funded through external financing sources and cash
from operations.

The actual cash distributions paid by the Partnership to its
partners occur within 45 days after the end of each
quarter. Since second quarter 2007, the Partnership has
increased its quarterly cash distribution 7 times. During
that time period, the Partnership has increased its quarterly
distribution by 62% from $0.3375 per common unit, or $1.35 on an
annualized basis, to $0.5475 per common unit, or $2.19 on an
annualized basis, based on the 2010 fourth quarter distribution
management plans to recommend to the General Partners
board of directors.

Overview of
Presentation

In the sections that follow, we present in detail the basis for
our belief that we will be able to fully fund our initial
quarterly dividend of $0.2575 per share of common stock for each
quarter through the quarter ending December 31, 2011. In
these sections, we present three tables, including:



our Unaudited Pro Forma Available Cash, in which we
present the amount of available cash we would have had available
for dividends to our shareholders on a pro forma basis for the
year ended December 31, 2009 and for the twelve months
ended September 30, 2010; and



our TRC Minimum Estimated Cash Available for Distribution
for the Twelve Month Period Ending December 31, 2011
and TRC Minimum Estimated Cash Available for Distribution
for the Three Month Period Ending December 31, 2010
in which we present our estimate of the Adjusted EBITDA
necessary for the Partnership to pay distributions to its
partners, including us, to enable us to have sufficient cash
available for distribution to fund quarterly dividends on all
outstanding common shares for each quarter through the quarter
ending December 31, 2011.

Targa Resources
Corp. Unaudited Pro Forma Available Cash for the Year Ended
December 31, 2009 and the Twelve Months Ended
September 30, 2010

Our pro forma available cash for the year ended
December 31, 2009 and the twelve months ended
September 30, 2010 would have been sufficient to pay the
initial quarterly dividend of $0.2575 per share of common
stock outstanding following the completion of this offering.

Pro forma cash available for distribution includes estimated
incremental general and administrative expenses we will incur as
a result of being a public corporation, such as costs associated
with preparation and distribution of annual and quarterly
reports to shareholders, tax returns, investor relations,
registrar and transfer agent fees, director compensation and
incremental insurance costs, including director and officer
liability insurance. We expect that these items will increase
our annual general and administrative expenses by approximately
$1 million.

The table below reconciles the Partnerships historical
financial results to our minimum cash available for distribution
and illustrates that we would have had cash distributions on our
interests in the Partnership sufficient to pay dividends to our
shareholders at the initial quarterly dividend of $0.2575 per
share. The table reconciles the Partnerships historical
financial results to its Adjusted EBITDA for the year ended
December 31, 2009 and for the twelve months ended
September 30, 2010 and then reconciles Adjusted EBITDA to
pro forma cash available for distribution to all of the
Partnerships unitholders.

The Partnerships pro forma cash available for distribution
is derived from its historical financial statements included in
its Current Report on
Form 8-K
filed with the SEC on October 4, 2010, and its Quarterly
Report on
Form 10-Q
filed with the SEC on November 5, 2010. Under common
control accounting, the Partnerships financial results
include the historical financial results of the assets acquired
from us. The only pro forma adjustments to such historical
financial results are to (i) present prior period interest
expense based on the Partnerships current debt balance as
reflected in the pro forma cash interest expense line in the
table below and (ii) current units outstanding of
75,545,409 units for all

periods presented. The pro forma cash available for distribution
should not be considered indicative of our results of operations
had the transactions contemplated in our unaudited pro forma
condensed consolidated financial statements actually been
consummated on January 1, 2009.

Pro forma cash available for distribution to Partnership
unitholders(5)

260.7

255.5

Partnerships debt covenant
ratios(6)

Interest coverage ratio of not less than 2.25 to 1.0

3.7

x

3.7

x

Consolidated leverage ratio of not greater than 5.5 to 1.0

3.5

x

3.6

x

Consolidated senior leverage ratio of not greater than 4.0
to 1.0

1.8

x

1.9

x

Estimated minimum cash available for distribution to
Partnership unitholders

Estimated minimum cash distributions to us:

2% general partner interest

3.8

3.8

Incentive distribution
rights(7)

21.4

21.4

Common units

25.5

25.5

Pro forma cash distributions to us

50.7

50.7

Pro forma cash distributions to public unitholders

139.9

139.9

Total pro forma cash distributions by the Partnership

190.6

190.6

Excess / (Shortfall)

70.1

64.9

Targa Resources Corp.
Data(8)

Pro forma cash distributions to be received from the Partnership

$

50.7

$

50.7

Plus / (Less):

General and administrative
expenses(9)

(5.4

)

(5.4

)

Cash interest
expense(10)

(3.4

)

(3.4

)

Interest income

1.7

1.7

Minimum estimated cash available for distribution

43.6

43.6

Excess / (Shortfall)





Expected dividend per share

1.03

1.03

Total dividends paid to stockholders

$

43.6

$

43.6

(1)

Gross margin is a non-GAAP
financial measure and is discussed under Managements
Discussion and Analysis of Financial Condition and Results of
OperationsHow We Evaluate Our Operations.

(2)

Operating margin is a non-GAAP
financial measure and is discussed under Managements
Discussion and Analysis of Financial Condition and Results of
OperationsHow We Evaluate Our Operations.

(3)

Adjusted EBITDA is presented
because we believe it provides additional information with
respect to both the performance of our fundamental business
activities as well as our ability to meet future debt service,
capital expenditures and working capital requirements. It is a
non-GAAP financial measure and is not intended to be used in
lieu of the GAAP presentation of net income.

(4)

For the twelve months ended
September 30, 2010, the Partnerships pro forma cash
interest expense includes (i) $35.0 million of
interest expense related to borrowings under the revolving
credit facility based on an average balance of
$727.3 million at an average interest rate of 4.8%
(comprised of 1% LIBOR plus a borrowing spread of 2.75% plus
interest rate hedge settlement of 1.1%);
(ii) $62.9 million of interest expense related to the
$690 million of senior unsecured notes with a weighted
average interest rate of approximately 9.1% and
(iii) $3.2 million of commitment fees and letter of
credit fees. After giving effect to LIBOR swaps for
$300 million of the Partnerships revolving credit
facility, a 1.0% change in LIBOR would result in a change in
interest expense for the period of $4.3 million.

For the twelve months ended
December 31, 2009, the Partnerships pro forma cash
interest expense includes (i) $33.6 million of
interest expense related to borrowings under the revolving
credit facility based on an average balance of
$684.5 million at an average interest rate of 4.9%
(comprised of 1% LIBOR plus a spread of 2.75% plus interest rate
hedge settlement of 1.2%); (ii) $62.9 million of
interest expense related to the $690 million of senior
unsecured notes with a weighted average interest rate of

approximately 9.1% and
(iii) $4.5 million of commitment fees and letter of
credit fees. After giving effect to LIBOR swaps for
$300 million of the Partnerships revolving credit
facility, a 1.0% change in LIBOR would result in a change in
interest for the period of $3.9 million.

Cash interest expense excludes
$5.9 million of non-cash interest expense for both periods.

(5)

The Partnerships pro forma
cash available for distribution is presented because we believe
it is used by investors to evaluate the ability of the
Partnership to make quarterly cash distributions. It is a
non-GAAP financial measure and is not intended to be used in
lieu of the GAAP presentation of net income.

(6)

The Partnerships credit
agreement and indentures contain certain financial covenants.
The Partnerships revolving credit facility requires that,
at the end of each fiscal quarter, the Partnership must maintain:



an interest coverage ratio, defined
as the ratio of the Partnerships consolidated adjusted
EBITDA (as defined in the Amended and Restated Credit Agreement)
for the four consecutive fiscal quarters most recently ended to
the consolidated interest expense (as defined in the Amended and
Restated Credit Agreement) for such period, of no less than 2.25
to 1.0;



a Consolidated Leverage Ratio,
defined as the ratio of the Partnerships consolidated
funded indebtedness (as defined in the Amended and Restated
Credit Agreement) to consolidated adjusted EBITDA, for the four
fiscal quarters most recently ended, that is not greater than
5.5 to 1.0; and



a Consolidated Senior Leverage
ratio, defined as the ratio of the Partnerships
consolidated funded indebtedness, excluding unsecured note
indebtedness, to consolidated adjusted EBITDA, for the four
fiscal quarters most recently ended, that is not greater than
4.0 to 1.0.

In addition, the indentures
relating to the Partnerships senior notes require that the
Partnership have a fixed charge coverage ratio for the most
recently ended four fiscal quarters of not less than 1.75 to 1.0
in order to make distributions, subject to certain exceptions.
This ratio is approximately equal to the interest coverage ratio
described above. As indicated in the table, the
Partnerships pro forma EBITDA would have been sufficient
to permit cash distributions under the terms of its credit
agreement and indentures.

(7)

Our incentive distributions are
based on the Partnerships 75,545,409 outstanding common
units as of November 1, 2010 and the Partnerships
fourth quarter 2010 quarterly distribution of $0.5475 per unit,
or $2.19 per unit on an annualized basis, that management plans
to recommend to the General Partners board of directors.

(8)

We will have no debt outstanding
under TRIs revolving credit facility, and accordingly, we
have not presented credit ratios for this facility in the table.
Pursuant to the terms of this facility at the end of each fiscal
quarter, TRI must maintain:



an interest coverage ratio, defined
as the ratio of our consolidated adjusted EBITDA (as defined in
the revolving credit agreement) for the four consecutive fiscal
quarters most recently ended to the consolidated interest
expense (as defined in the revolving credit agreement) for such
period, of no less than 1.5 to 1.0;



a Consolidated Leverage Ratio,
defined as the ratio of our consolidated funded indebtedness (as
defined in the revolving credit agreement) to consolidated
adjusted EBITDA, for the four fiscal quarters most recently
ended, that is not greater than 5.75 to 1.0 and becomes more
restrictive over time.

(9)

General and administrative expenses
include $1 million of incremental public company expenses.

(10)

Following this offering and
excluding debt of the Partnership, our only outstanding debt
will be the Holdco Loan under which we have the election to pay
interest in cash or in kind. We have assumed that we will pay
interest in cash at an assumed interest rate of LIBOR plus a
spread of 3.0%. The Holdco Loan agreement has no restrictive
covenants which would impact our ability to pay dividends.

TRC Minimum
Estimated Cash Available for Distribution for the Twelve Month
Period Ending December 31, 2011

Set forth below is a forecast of the TRC Minimum Estimated
Cash Available for Distribution that supports our belief
that we expect to generate sufficient cash flow to pay a
quarterly dividend of $0.2575 per common share on all of
our outstanding common shares for the twelve months ending
December 31, 2011, based on assumptions we believe to be
reasonable.

Our minimum estimated cash available for distribution reflects
our judgment as of the date of this prospectus of conditions we
expect to exist and the course of action we expect to take
during the twelve months ending December 31, 2011. The
assumptions disclosed under  Assumptions and
Considerations below are those that we believe are
significant to our ability to generate such minimum estimated
cash available for distribution. We believe our actual results
of operations and cash flows for the twelve months ending
December 31, 2011 will be sufficient to generate our
minimum

estimated cash available for distribution for such period;
however, we can give you no assurance that such minimum
estimated cash available for distribution will be achieved.
There will likely be differences between our minimum estimated
cash available for distribution for the twelve months ending
December 31, 2011 and our actual results for such period
and those differences could be material. If we fail to generate
the minimum estimated cash available for distribution for the
twelve months ending December 31, 2011, we may not be able
to pay cash dividends on our common shares at the initial
dividend rate stated in our cash dividend policy for such period.

Our minimum estimated cash available for distribution required
to pay dividends to all our outstanding shares of common stock
at the estimated annual initial dividend rate of $1.03 per share
is approximately $43.6 million. Our minimum estimated cash
available for distribution is comprised of cash distributions
from our limited and general partnership interests in the
Partnership, including the IDRs, less general and administrative
expenses, less cash interest expense, if any, less federal
income taxes, less capital contributions to the Partnership and
less reserves established by our board of directors.
Substantially all of our cash flow will be generated from our
limited and general partnership interests in the Partnership. In
order for our minimum estimated cash available for distribution
to be approximately $43.6 million, we estimate that the
Partnership must have minimum estimated cash available for
distribution for the twelve months ending December 31, 2011
of $190.6 million, which would be sufficient to fund the
Partnerships recommended distribution for the quarter
ended December 31, 2010 of $2.19 per common unit on an
annualized basis.

In order for the Partnership to have minimum estimated cash
available for distribution of $190.6 million, we estimate
that it must generate Adjusted EBITDA of at least
$403.5 million for the twelve months ending
December 31, 2011 after giving effect to a
$58.8 million cash reserve. As set forth in the table below
and as further explained under Assumptions and
Considerations, we believe the Partnership will produce
minimum estimated cash available for distribution of
$190.6 million for the twelve months ending
December 31, 2011.

We do not as a matter of course make public projections as to
future operations, earnings or other results. However,
management has prepared the minimum estimated cash available for
distribution and assumptions set forth below to substantiate our
belief that we will have sufficient cash available to pay the
estimated annual dividend rate to our stockholders for the
twelve months ending December 31, 2011. The accompanying
prospective financial information was not prepared with a view
toward complying with the published guidelines of the SEC or the
guidelines established by the American Institute of Certified
Public Accountants with respect to prospective financial
information, but, in the view of our management, was prepared on
a reasonable basis, reflects the best currently available
estimates and judgments and presents, to the best of
managements knowledge and belief, the assumptions on which
we base our belief that we can generate the minimum estimated
cash available for distribution necessary for us to have
sufficient cash available for distribution to pay the estimated
annual dividend rate to all of our stockholders for the twelve
months ending December 31, 2011. However, this information
is not fact and should not be relied upon as being necessarily
indicative of future results, and readers of this prospectus are
cautioned not to place undue reliance on the prospective
financial information. The prospective financial information
included in this prospectus has been prepared by, and is the
responsibility of, our management. PricewaterhouseCoopers LLP
has neither examined, compiled nor performed any procedures with
respect to the accompanying prospective financial information
and, accordingly, PricewaterhouseCoopers LLP does not express an
opinion or any other form of assurance with respect thereto. The
PricewaterhouseCoopers LLP reports included in this prospectus
relate to our historical financial information. Such reports do
not extend to the prospective financial information of the
Partnership or us and should not be read to do so.

We are providing the minimum estimated cash available for
distribution and related assumptions for the twelve months
ending December 31, 2011 to supplement our pro forma and
historical financial statements in support of our belief that we
will have sufficient available cash to allow us to pay cash
dividends on all of our outstanding shares of common stock for
each quarter in the twelve month period ending December 31,
2011 at our stated initial quarterly dividend rate. Please read
below under  Assumptions and
Considerations for further information as to the
assumptions we have made for the preparation of the minimum
estimated cash available for distribution set forth below.

We do not undertake any obligation to release publicly the
results of any future revisions we may make to the assumptions
used in generating our minimum estimated cash available for
distribution for the twelve months ending December 31, 2011
or to update those assumptions to reflect events or
circumstances after the date of this prospectus. Therefore, you
are cautioned not to place undue reliance on this information.

Adjusted EBITDA is presented
because we believe it provides additional information with
respect to both the performance of our fundamental business
activities as well as our ability to meet future debt service,
capital expenditures and working capital requirements. It is a
non-GAAP financial measure and is not intended to be used in
lieu of the GAAP presentation of net income.

The Partnerships estimated
minimum cash available for distribution is presented because we
believe it is used by investors to evaluate the ability of the
Partnership to make quarterly cash distributions. It is a
non-GAAP financial measure and is not intended to be used in
lieu of the GAAP presentation of net income.

(7)

The Partnerships credit
agreement and indentures contain certain financial covenants.
The Partnerships revolving credit facility requires that,
at the end of each fiscal quarter, the Partnership must maintain:



an interest coverage ratio, defined
as the ratio of the Partnerships consolidated adjusted
EBITDA (as defined in the Amended and Restated Credit Agreement)
for the four consecutive fiscal quarters most recently ended to
the consolidated interest expense (as defined in the Amended and
Restated Credit Agreement) for such period, of no less than 2.25
to 1.0;



a Consolidated Leverage Ratio,
defined as the ratio of the Partnerships consolidated
funded indebtedness (as defined in the Amended and Restated
Credit Agreement) to consolidated adjusted EBITDA, for the four
fiscal quarters most recently ended, that is not greater than
5.5 to 1.0; and



a Consolidated Senior Leverage
ratio, defined as the ratio of the Partnerships
consolidated funded indebtedness, excluding unsecured note
indebtedness, to consolidated adjusted EBITDA, for the four
fiscal quarters most recently ended, that is not greater than
4.0 to 1.0.

In addition, the indentures
relating to the Partnerships existing senior notes require
that the Partnership have a fixed charge coverage ratio for the
most recently ended four fiscal quarters of not less than 1.75
to 1.0 in order to make distributions, subject to certain
exceptions. This ratio is approximately equal to the interest
coverage ratio described above. As indicated by the table, we
estimate that the Partnerships pro forma EBITDA would be
sufficient to permit cash distributions, under the terms of its
credit agreement and indentures.

(8)

Based on the Partnerships
75,545,409 outstanding common units as of November 1, 2010
and the Partnerships fourth quarter 2010 quarterly
distribution of $0.5475 per unit, or $2.19 per unit on an
annualized basis, that management plans to recommend to the
General Partners board of directors.

We expect that we will have no debt
outstanding under TRIs revolving credit facility, and
accordingly, we have not presented credit ratios for this
facility in the table. Pursuant to the terms of this facility at
the end of each fiscal quarter, TRI must maintain:



an interest coverage ratio, defined
as the ratio of our consolidated adjusted EBITDA (as defined in
the revolving credit agreement) for the four consecutive fiscal
quarters most recently ended to the consolidated interest
expense (as defined in the revolving credit agreement) for such
period, of no less than 1.5 to 1.0;



a Consolidated Leverage Ratio,
defined as the ratio of our consolidated funded indebtedness (as
defined in the revolving credit agreement) to consolidated
adjusted EBITDA, for the four fiscal quarters most recently
ended, that is not greater than 5.75 to 1.0 and becomes more
restrictive over time.

(10)

The Holdco Loan agreement has no
restrictive covenants which would impact our ability to pay
dividends.

(11)

General and administrative expenses
include $3 million of public company expenses, including
$1 million of estimated incremental public company
expenses. TRI Resources Inc. was required to file reports under
the Securities Exchange Act of 1934 until January 2010, and,
accordingly, recognized costs associated with being a public
company prior to that time.

Assumptions and
Considerations

General

We estimate that our ownership interests in the Partnership will
generate sufficient cash flow to enable us to pay our initial
quarterly dividend of $0.2575 per share on all of our shares for
the four quarters ending December 31, 2011. Our ability to
make these dividend payments assumes that the Partnership will
pay its current quarterly distribution of $0.5475 per common
unit for each of the four quarters ending December 31,
2011, which means that the total amount of cash distributions we
will receive from the Partnership for that period would be
$50.7 million.

The primary determinant in the Partnerships ability to pay
a distribution of $0.5475 per common unit for each of the four
quarters ending December 31, 2011, after giving effect to a
$58.8 million cash reserve, is its ability to generate
Adjusted EBITDA of at least $403.5 million during the
period, which in turn is dependent on its ability to generate
operating margin of $544.3 million. Our estimate of the
Partnerships ability to generate at least this amount of
operating margin is based on a number of assumptions including
those set forth below.

While we believe that these assumptions are generally consistent
with the actual performance of the Partnership and are
reasonable in light of our current beliefs concerning future
events, the assumptions are inherently uncertain and are subject
to significant business, economic, regulatory and competitive
risks and uncertainties that could cause actual results to
differ materially from those we anticipate. If these assumptions
are not realized, the actual available cash that the Partnership
generates, and thus the cash we would receive from our ownership
interests in the Partnership, could be substantially less than
that currently expected and could, therefore, be insufficient to
permit us to make our initial quarterly dividend on our shares
for the forecasted period. In that event, the market price of
our shares may decline materially. Consequently, the statement
that we believe that we will have sufficient cash available to
pay the initial dividend on our shares of common stock for each
quarter through December 31, 2011, should not be regarded
as a representation by us or the underwriters or any other
person that we will make such a distribution. When reading this
section, you should keep in mind the risk factors and other
cautionary statements under the heading Risk Factors
in this prospectus.

Commodity Price Assumptions. As of
October 29, 2010, the NYMEX 2011 calendar strip prices for
natural gas and crude oil were $4.39 per MMBtu and
$84.28 per Bbl. These prices are 13.9% and 0.9%

below the forecasted prices of $5.10 per MMBtu and
$85.00 per Bbl used to calculate estimated Adjusted EBITDA.

Twelve Months Ended

December 31, 2009

September 30, 2010

December 31, 2011

Natural Gas

$3.99/MMBtu

$4.48/MMBtu

$5.10/MMBtu

Ethane

$0.48/gallon

$0.61/gallon

$0.47/gallon

Propane

$0.84/gallon

$1.12/gallon

$1.05/gallon

Isobutane

$1.19/gallon

$1.53/gallon

$1.46/gallon

Normal butane

$1.08/gallon

$1.44/gallon

$1.42/gallon

Natural gasoline

$1.31/gallon

$1.75/gallon

$1.80/gallon

Crude oil

$59.80/Bbl

$76.99/Bbl

$85.00/Bbl

In addition, the Partnerships estimated Adjusted EBITDA
reflects the effect of its commodity price hedging program under
which it has hedged a portion of the commodity price risk
related to the sale of its expected natural gas, NGL, and
condensate equity volumes that result from its
percent-of-proceeds
processing arrangements for our Field Gathering and Processing
and the LOU portion of our Coastal Gathering and Processing
operations. Please see Managements Discussion and
Analysis of Financial Condition and Results of
OperationsFactors That Significantly Affect Our
ResultsContract Terms and Contract Mix and the Impact of
Commodity Prices. The table below summarizes the
Partnerships hedged volumes for 2011 under derivative
arrangements that are in place as of September 30, 2010. We
estimate that these hedged volumes correspond to approximately
65% to 75% of the Partnerships expected natural gas equity
volumes and approximately 50% to 60% of Partnerships
expected NGLs and condensate equity volumes for 2011. The
percentages hedged are derived by dividing the notional volumes
hedged by a range of estimated equity volumes for 2011.

Natural Gas

NGL

Condensate

Hedged volume  swaps

30,100 MMBtu/d

7,000 Bbls/d

750 Bbls/d

Weighted average price  swaps

$6.32 per MMBtu

$0.85 per gallon

$77.00 per Bbl

Hedged  volume floors

253 Bbls/d

Weighted average price  floors

$1.44 per gallon

The table below compares selected financial and volumetric data
for the Partnership for the twelve months ending December 31,
2011 to the twelve months ended September 30, 2010 and
December 31, 2009.

Volume assumptions. For the twelve months
ended September 30, 2010, plant inlet volumes increased 7%
over volumes for the twelve months ended December 31, 2009.
For 2011, we expect a continued increase of 8% over the twelve
months ended September 30, 2010. The volume increase is
driven by additional volumes on the Partnerships VESCO
system (see   Coastal Gathering and
Processing Segment Assumptions for more detail), and
expected new drilling and workover activity in our Field
Gathering and Processing segment (see  
Field Gathering and Processing Segment Assumptions for
more detail).

Fractionation volumes for 2011 are forecasted to increase 32%
over the twelve months ended September 30, 2010 primarily
due to the 78 MBbl/d CBF expansion, which is expected to be
in service in the second quarter of 2011.

Revenue assumptions. 2011 revenue is
forecasted to increase 15% over the twelve months ended
September 30, 2010 and 35% over 2009. The increase in
revenue is primarily due to higher plant inlet and fractionation
volumes and higher commodity prices as presented in the table
above.

Operating expense assumptions. Operating
expenses are forecasted to increase 19% over the twelve months
ended September 30, 2010 and 23% over 2009 mostly due to
expanded operations in our Logistics segment resulting from the
CBF expansion and partial year addition of the benzene treater.
Also, expenses are forecasted to be higher for our Field
Gathering and Processing Segment mostly due to increased
connections resulting from new drilling activity.

Operating margin assumptions. For the twelve
months ended September 30, 2010, operating margin increased
10% over operating margin for the twelve months ended
December 31, 2009 largely due to increases in the Field
Gathering and Processing segment and the Coastal Gathering and
Processing Segment. For full year 2011, we expect a continued
increase of 4% over the twelve months ended September 30,
2010 largely due to increases in the Field Gathering and
Processing segment and the Logistics Assets segment (see
  Segment Operating Margin
Assumptions for more detail).

Maintenance Capital Expenditures assumptions,
net. The Partnerships maintenance capital
expenditures increased for the twelve months ended
September 30, 2010 relative to 2009 because of a larger
number of well connections associated with higher drilling
activity levels for assets in our Field Gathering and Processing
segment. We expect drilling activity to increase further, which
will result in higher maintenance capital expenditures in 2011.

Segment Operating Margin Assumptions. Based on
the pricing and other assumptions outlined above and the segment
information and other assumptions discussed below, we estimate
forecasted operating margin for the Partnerships segments
for the twelve months ending December 31, 2011 as

shown in following table. Selected operating and historical
financial data for the Partnership for the twelve months ended
September 30, 2010 and the twelve months ended December 31,
2009 is also shown.

Twelve Months Ending

December 31, 2011

December 31, 2009

September 30, 2010

(Estimated)

(In millions)

Natural Gas Gathering and Processing

Field Gathering and Processing Segment

$

183.2

$

236.6

$

245.6

Coastal Gathering and Processing Segment

89.7

111.6

102.0

NGL Logistics and Marketing

Logistics Assets Segment

74.4

79.8

118.6

Marketing and Distribution Segment

82.9

78.1

65.6

Other

46.2

16.7

12.5

Total operating margin

$

476.4

$

522.8

$

544.3

Natural Gas Gathering and Processing. The
Partnerships Natural Gas Gathering and Processing business
includes assets used in the gathering of natural gas produced
from oil and gas wells and processing this raw natural gas into
merchantable natural gas by removing impurities and extracting a
stream of combined NGLs or mixed NGLs. The Field Gathering and
Processing segment assets are located in North Texas and in the
Permian Basin of Texas and New Mexico. The Coastal Gathering and
Processing segment assets are located in the onshore and near
offshore regions of the Louisiana Gulf Coast accessing onshore
and offshore gas supplies. The Partnerships results of
operations are impacted by changes in commodity prices as well
as increases and decreases in the volume and thermal content of
natural gas that the Partnership gathers and transports through
its pipeline systems and processing plants.

Field Gathering and Processing Segment
Assumptions. The following table summarizes
selected operating and financial data for the Partnership for
the twelve months ending December 31, 2011 compared to
historical data for the twelve months ended September 30,
2010 and the twelve months ended December 31, 2009.

Twelve Months Ending

December 31, 2011

December 31, 2009

September 30, 2010

(Estimated)

Plant natural gas inlet,
MMcf/d

581.9

579.2

660.3

Gross NGL Production, MBbl/d

69.8

69.9

80.2

Operating margin, $ in millions

$

183.2

$

236.6

$

245.6

We forecast plant inlet volumes will increase by 14.0% for the
twelve months ending December 31, 2011 as compared to the
twelve months ended September 30, 2010 based on expected
producer drilling and workover activity. New drilling is
expected to come from liquids rich hydrocarbons plays including
the Wolfberry Trend and Canyon Sands plays, which can be
accessed by SAOU, the Wolfberry and Bone Springs plays, which
can be accessed by the Sand Hills system, and the Barnett Shale
and Fort Worth Basin, including Montague, Cooke, Clay and
Wise counties, which can be accessed by the North Texas system.

Operating margin increased 29% from 2009 to the twelve months
ended September 30, 2010 primarily as a result of higher
commodity prices. Operating margin is estimated to increase by
3.8% to $245.6 million for the twelve months ending
December 31, 2011 as compared to $236.6 million for
the twelve months ended September 30, 2010 due to increases
in plant inlet volumes partially offset by increased operating
expenses and lower NGL prices.

Coastal Gathering and Processing Segment
Assumptions. The following table summarizes
selected operating and financial data for the Partnership for
the twelve months ending December 31,

2011 compared to historical data for the twelve months ended
September 30, 2010 and the twelve months ended
December 31, 2009.

Twelve Months Ending

December 31, 2011

December 31, 2009

September 30, 2010

(Estimated)

Plant natural gas inlet,
MMcf/d

1,557.8

1,709.3

1,810.0

Gross NGL Production, MBbl/d

48.5

51.2

58.2

Operating margin, $ in millions

$

89.7

$

111.6

$

102.0

Plant inlet volumes increased by 10% for the twelve months ended
September 30, 2010 as compared to full year 2009 as a
result of the recovery from the impacts of hurricanes in 2008.
Plant inlet volumes are forecasted to increase 6% for the twelve
months ending December 31, 2011 as compared to the twelve
months ended September 30, 2010 based on the addition of
new supply to our VESCO system primarily from anticipated
additional production from existing customers.

Operating margin is estimated to be $102.0 million for the
twelve months ending December 31, 2011 as compared to
$111.6 million for the twelve months ended
September 30, 2010. The decrease in operating margin is
primarily attributable to lower margins resulting from lower
forecasted liquids prices and higher forecasted natural gas
prices and leaner inlet gas partially offset by forecasted
increases in VESCO volumes.

NGL Logistics and Marketing. The
Partnerships NGL Logistics and Marketing segment includes
all the activities necessary to fractionate mixed NGLs into
finished NGL productsethane, propane, normal butane,
isobutane and natural gasolineand provides certain value
added services, such as the storage, terminalling,
transportation, distribution and marketing of NGLs. The assets
in this segment are generally connected indirectly to and
supplied, in part, by the Partnerships gathering and
processing segments and are predominantly located in Mont
Belvieu, Texas and Southwestern Louisiana. The Logistics Assets
segment uses its platform of integrated assets to store,
fractionate, treat and transport NGLs, typically under fee-based
and margin-based arrangements. The Marketing and Distribution
segment covers all activities required to distribute and market
mixed NGLs and NGL products. It includes (1) marketing and
purchasing NGLs in selected United States markets,
(2) marketing and supplying NGLs for refinery customers,
and (3) transporting, storing and selling propane and
providing related propane logistics services to multi-state
retailers, independent retailers and other end users.

Logistics Assets Segment Assumptions. The
following table summarizes selected operating and financial data
for the Partnership for the twelve months ending
December 31, 2011 compared to pro forma historical data for
the twelve months ended September 30, 2010 and the twelve
months ended December 31, 2009.

Twelve Months Ending

December 31, 2011

December 31, 2009

September 30, 2010

(Estimated)

Fractionation volumes, MBbl/d

217.2

221.4

291.6

Treating volumes, MBbl/d

21.9

21.4

27.5

Operating margin, $ in millions

$

74.4

$

79.8

$

118.6

Fractionation and treating volumes for 2011 are forecasted to
increase approximately 31% relative to the twelve months ended
September 30, 2010 primarily due to the 78 MBbl/d CBF
expansion, which is expected to be in-service in the second
quarter of 2011, and to the Mt. Belvieu Benzene treater, which
is expected to be in-service in the fourth quarter of 2011.

Operating margin is estimated to increase approximately 49% to
$118.6 million for 2011 as compared to $79.8 million
for the twelve months ended September 30, 2010. This
estimated increase is due to the higher fractionation and
treating volumes; renewal of existing contracts at higher rates;
the incremental price impact of the new contracts for the CBF
expansion and the partial year impact of the Benzene treater
described under Business of Targa Resources Partners
LPPartnership Growth Drivers.

Marketing and Distribution Segment
Assumptions. The following table summarizes
selected operating and financial data for the Partnership for
the twelve months ending December 31, 2011 compared to
historical data for the twelve months ended September 30,
2010 and the twelve months ended December 31, 2009.

Twelve Months Ending

December 31, 2011

December 31, 2009

September 30, 2010

(Estimated)

NGL Sales, MBbl/d

276.1

246.1

254.9

Operating margin, $ in millions

$

82.9

$

78.1

$

65.6

The decline in volumes from the year ended December 31,
2009 to the twelve months ended September 30, 2010 was the
result of a contract renegotiation which resulted in lower
volumes but higher per barrel margins. We expect volumes in 2011
to increase slightly over volumes for the twelve months ended
September 30, 2010 primarily due to some refinery outages
in 2010 that reduced our supply of NGLs.

Operating margin is estimated to be $65.6 million for the
twelve months ending December 31, 2011 which represents a
$12.5 million decline from the twelve months ended
September 30, 2010. The decrease is primarily due to lower
expected margins on the sales of inventories. The Marketing and
Distribution segment benefitted from a generally rising pricing
environment that produced gains from sales of inventory over the
twelve month periods ended September 30, 2010 and
December 31, 2009.

Other. Other primarily reflects our hedge
settlements which are the cash receipts or payments due to
market prices settling above or below the prices of our hedging
instruments. Contribution to operating margin from other
decreased from $46.2 million for the twelve months ended
December 31, 2009 to $16.7 million for the twelve
months ended September 30, 2010 and is estimated to
decrease further to $12.5 million for the twelve months
ending December 31, 2011. The decrease from 2009 through
the forecast period is primarily due to a trend of lower hedged
volumes and higher commodity prices which result in lower cash
settlements.

Other
Assumptions



Depreciation and Amortization Expenses. The
Partnerships depreciation and amortization expenses are
estimated to be $175.4 million for the twelve months ending
December 31, 2011, as compared to $170.1 million for
the twelve months ended September 30, 2010. Depreciation
and amortization is expected to increase as a result of the
Partnerships organic growth projects and maintenance
capital expenditures.



General and Administrative Expenses. The
Partnerships general and administrative expenses include
its public company expenses and are estimated to be
$110.3 million for the twelve months ending
December 31, 2011, as compared to $116.6 million for
the twelve months ended September 30, 2010. General and
administrative expenses are expected to decrease as a result of
lower estimated compensation expense and decreased professional
services associated with 2010 transactions.



Interest Expense. The Partnerships
interest expense is estimated to be $110.3 million for the
twelve months ending December 31, 2011. This amount
includes (i) $63.0 million of interest expense related
to the $690 million of senior unsecured notes with a
weighted average interest rate of approximately 9.1%,
(ii) $39.0 million of interest expense, after giving
effect to the impact of interest rate hedges, under the
Partnerships revolving credit facility, at an assumed
interest rate of approximately 3.8% (based on a 1% LIBOR plus a
spread of 2.75%) and (iii) $8.3 million of commitment
fees, amortization of debt issuance costs and letter of credit
fees. Pro forma as adjusted for the Versado acquisition, the
VESCO acquisition and the Partnerships debt and equity
offerings in August 2010, the Partnerships revolving
credit facility had a balance of $753.3 million on
September 30, 2010. The balance is estimated to be
$778.3 million at December 31, 2010 with the increase
attributable to expansion capital expenditures. During the
twelve month period ending December 31, 2011, we estimate that
the Partnership will borrow $129.0 million to fund

growth capital expenditures. After giving effect to LIBOR swaps
for $300 million of the Partnerships revolving credit
facility, a 1.0% change in LIBOR would result in a change in
interest for the forecast period of $5.4 million.



Equity in Earnings of Unconsolidated
Investment. The Partnerships equity in
earnings of unconsolidated investment is estimated to be
$11.5 million for the twelve months ending
December 31, 2011, compared to $5.6 million for the
twelve months ended September 30, 2010. The
Partnerships equity in earnings of unconsolidated
investment is related to its investment in GCF, and the increase
is attributable to price increases for fractionation services.



Noncontrolling Interest Adjustment. Net income
attributable to noncontrolling interest is estimated to be
$31.2 million for the twelve months ending
December 31, 2011, compared to $25.5 million for the
twelve months ended September 30, 2010. Net income
attributable to noncontrolling interest is associated with
minority ownership stakes in Versado, VESCO and CBF. In the
reconciliation of Partnership net income to Partnership Adjusted
EBITDA, the non-controlling interest adjustment reflects
depreciation expense attributable to the minority ownership
stake.



Expansion Capital Expenditures, net and
investments. The Partnerships forecasted
expansion capital expenditures for the twelve months ending
December 31, 2011 are estimated to be approximately
$129.0 million net of minority partnership share and
primarily consist of the benzene treating project, the
expansions of CBF and GCF and various gathering and processing
system expansions. See Business of Targa Resources
Partners LPPartnership Growth Drivers. These
forecasted capital expenditures are expected to be funded from
borrowings under its revolving credit facility.



Maintenance Capital Expenditures, net. The
Partnerships maintenance capital expenditures for the
twelve months ending December 31, 2011 are estimated to be
approximately $49.7 million, net of minority interest
share, compared to $40.4 million on a pro forma basis for
the twelve months ended September 30, 2010. These capital
expenditures are expected to fund the development of additional
gathering and processing capacity in areas in which producers
have increased drilling activity. The estimated amount excludes
approximately $8 million of capital expenditures associated
with the Versado System that will be reimbursed to the
Partnership by us. See Assumptions for Targa
Resources Corp.Capital Expenditure Reimbursement to the
Partnership.



Compliance with Debt Agreements. We expect
that we and the Partnership will remain in compliance with the
financial covenants in our respective financing arrangements.



Regulatory and Other. We have assumed that
there will not be any new federal, state or local regulation of
portions of the energy industry in which we and the Partnership
operate, or a new interpretation of existing regulation, that
will be materially adverse to our or the Partnerships
business and market, regulatory, insurance and overall economic
conditions will not change substantially.

Assumptions for
Targa Resources Corp.



Financing and Interest Expense. We assume that
our Holdco loan will have an average balance of approximately
$85.0 million during 2011. Pursuant to the terms of such
loan, we pay interest either in cash or in kind (PIK). We have
assumed the cash pay option of LIBOR plus a margin of 3%.



Interest Income. We estimate that we will
invest in a combination of cash and equivalents, treasuries and
liquid, investment grade securities until which time the cash is
necessary to satisfy these obligations. For the twelve months
ending December 31, 2011 we estimate such investments will
earn an average return of 2%.

Cash Taxes. We estimate that we will pay
approximately $14.3 million in taxes for the twelve months
ending December 31, 2011. This amount consists of
$16.9 million from tax liabilities, which resulted from
deferred gains for previous drop down transactions, partially
offset by taxable losses that reduce taxes by $2.6 million.
The $14.3 million of cash taxes due will be funded from our
cash reserve, discussed further below.



Capital Expenditure Reimbursement to the
Partnership. In connection with the sale of our
interests in Versado to the Partnership, we have agreed to
reimburse the Partnership for an estimated $19 million of
capital expenditures which are expected to be paid by the end of
2011 from our cash reserve, discussed further below.



Cash Reserve. We estimate that at the closing
of this offering we will have approximately $151 million of
cash which will be sufficient to pay current payables as well as
a $19 million capital expenditure reimbursement to be paid
to the Partnership by the end of 2011 and $88 million of
cash taxes which resulted from deferred gains from previous drop
down transactions and which will be paid over the next ten
years. We expect this cash balance, interest income earned on
this balance over time, and any retained cash resulting from
reserves established by our board of directors will be
sufficient to satisfy these obligations.

TRC Minimum
Estimated Cash Available for Distribution for the Three Month
Period Ending December 31, 2010

Set forth below is a forecast of the TRC Minimum Estimated
Cash Available for Distribution that supports our belief
that we expect to generate sufficient cash flow to pay a
quarterly dividend of $0.2575 per common share on all of our
outstanding common shares for the three months ending
December 31, 2010. We expect to pay a prorated dividend for
the portion of the fourth quarter of 2010 that we are public. We
believe our actual results of operations and cash flows for the
three months ending December 31, 2010 will be sufficient to
generate our minimum estimated cash available for distribution
for such period; however, we can give you no assurance that such
minimum estimated cash available for distribution will be
achieved. There will likely be differences between our minimum
estimated cash available for distribution for the three months
ending December 31, 2010 and our actual results for such
period and those differences could be material. If we fail to
generate the minimum estimated cash available for distribution
for the three months ending December 31, 2010, we may not
be able to pay a prorated cash dividend on our common shares at
the initial dividend rate stated in our cash dividend policy for
such period.

This forward-looking financial information included in this
prospectus has been prepared by, and is the responsibility of,
our management. PricewaterhouseCoopers LLP has neither examined,
compiled nor performed any procedures with respect to the
accompanying forward-looking financial information and,
accordingly, PricewaterhouseCoopers LLP does not express an
opinion or any other form of assurance with respect thereto. The
PricewaterhouseCoopers LLP reports included in this prospectus
relate to our historical financial information. Such reports do
not extend to this forward-looking financial information of the
Partnership or us and should not be read to do so. Please see
TRC Minimum Estimated Cash Available for Distribution for
the Twelve Month Period Ending December 31, 2011

Adjusted EBITDA is presented
because we believe it provides additional information with
respect to both the performance of our fundamental business
activities as well as our ability to meet future debt service,
capital expenditures and working capital requirements. It is a
non-GAAP financial measure and is not intended to be used in
lieu of the GAAP presentation of net income.

The Partnerships estimated
minimum cash available for distribution is presented because we
believe it is used by investors to evaluate the ability of the
Partnership to make quarterly cash distributions. It is a
non-GAAP financial measure and is not intended to be used in
lieu of the GAAP presentation of net income.

7.

The Partnerships credit
agreement and indentures contain certain financial covenants.
The Partnerships revolving credit facility requires that,
at the end of each fiscal quarter, the Partnership must maintain:



an interest coverage ratio, defined
as the ratio of the Partnerships consolidated adjusted
EBITDA (as defined in the Amended and Restated Credit Agreement)
for the four consecutive fiscal quarters most recently ended to
the consolidated interest expense (as defined in the Amended and
Restated Credit Agreement) for such period, of no less than 2.25
to 1.0;



a Consolidated Leverage Ratio,
defined as the ratio of the Partnerships consolidated
funded indebtedness (as defined in the Amended and Restated
Credit Agreement) to consolidated adjusted EBITDA, for the four
fiscal quarters most recently ended, that is not greater than
5.5 to 1.0; and

a Consolidated Senior Leverage
ratio, defined as the ratio of the Partnerships
consolidated funded indebtedness, excluding unsecured note
indebtedness, to consolidated adjusted EBITDA, for the four
fiscal quarters most recently ended, that is not greater than
4.0 to 1.0.

In addition, the indentures
relating to the Partnerships existing senior notes require
that the Partnership have a fixed charge coverage ratio for the
most recently ended four fiscal quarters of not less than 1.75
to 1.0 in order to make distributions, subject to certain
exceptions. This ratio is approximately equal to the interest
coverage ratio described above. As indicated by the table, we
estimate that the Partnerships pro forma EBITDA would be
sufficient to permit cash distributions, under the terms of its
credit agreement and indentures.

8.

Based on the Partnerships
75,545,409 outstanding common units as of November 1, 2010
and the Partnerships fourth quarter 2010 quarterly
distribution of $0.5475 per unit, or $2.19 per unit on an
annualized basis, that management plans to recommend to the
General Partners board of directors.

9.

We expect that we will have no debt
outstanding under TRIs revolving credit facility, and
accordingly, we have not presented credit ratios for this
facility in the table. Pursuant to the terms of this facility at
the end of each fiscal quarter, TRI must maintain:



an interest coverage ratio, defined
as the ratio of our consolidated adjusted EBITDA (as defined in
the revolving credit agreement) for the four consecutive fiscal
quarters most recently ended to the consolidated interest
expense (as defined in the revolving credit agreement) for such
period, of no less than 1.5 to 1.0;



a Consolidated Leverage Ratio,
defined as the ratio of our consolidated funded indebtedness (as
defined in the revolving credit agreement) to consolidated
adjusted EBITDA, for the four fiscal quarters most recently
ended, that is not greater than 5.75 to 1.0 and becomes more
restrictive over time.

10.

The Holdco Loan agreement has no
restrictive covenants which would impact our ability to pay
dividends.

11.

We expect to pay a prorated divided
for the portion of the fourth quarter of 2010 that we are
public. We estimate that we will have sufficient cash available
to pay the full amount of the dividend and, therefore, any
prorated portion thereof.

Assumptions and
Considerations

We estimate that our ownership interests in the Partnership will
generate sufficient cash flow to enable us to pay our initial
quarterly dividend of $0.2575 per share, which will be prorated
for the post-offering period, on all of our shares for the
quarter ending December 31, 2010. Our ability to make this
dividend payment assumes that the Partnership will pay its
quarterly distribution of $0.5475 per common unit that
management plans to recommend to the General Partners
board of directors for the fourth quarter ending
December 31, 2010, which means that the total amount of
cash distributions we will receive from the Partnership for that
period would be $12.7 million.

The primary determinant in the Partnerships ability to pay
a distribution of $0.5475 per common unit for the fourth quarter
ending December 31, 2010, after giving effect to a
$16.8 million cash reserve, is its ability to generate
Adjusted EBITDA of at least $108.7 million during the
period, which in turn is dependent on its ability to generate
operating margin of $141.5 million.

The estimates of the Adjusted EBITDA and operating margin to be
generated by the Partnership for the fourth quarter ending
December 31, 2010 assumes the following volume and
commodity price information:

Volume assumptions. Field Gathering and
Processing volumes reflect the impact of continued growth from
increased drilling activity. Coastal Gathering and Processing
daily volumes decline slightly as compared to the twelve months
ended September 30, 2010 due primarily to temporary
pipeline interruptions. Fractionation volumes reflect the stable
demand for fractionating services. The volumes for each of these
segments is set forth in the table above.

Commodity price assumptions. Commodity prices
are based on actual prices for October 2010 and market prices as
of November 4, 2010 for the remainder of the quarter.

General and Administrative Expenses. The
Partnerships general and administrative expenses include
its public company expenses and are estimated to be
$32.6 million for the three months ending December 31,
2010. The general and administrative expense for the three
months ending December 31, 2010 is higher than the
quarterly average for the twelve months ended September 30,
2010 due to increased compensation costs and drop down
transaction costs.

Interest Expense. The Partnerships
interest expense is estimated to be $25.7 million for the
three months ending December 31, 2010. This amount is based
on the Partnerships outstanding senior unsecured notes and
September 30, 2010 balance on the Partnerships
revolving credit facility and gives effect to expansion capital
expenditures funded during the three months ending
December 31, 2010.

Expansion Capital Expenditures, net. The
Partnerships forecasted expansion capital expenditures for
the three months ending December 31, 2010 are estimated to
be approximately $41.2 million, net of minority partnership
share, and primarily consist of expenditures on previously
announced expansion projects.

Maintenance Capital Expenditures, net. The
Partnerships maintenance capital expenditures for the
three months ending December 31, 2010 are estimated to be
approximately $20.0 million, net of minority interest
share. These capital expenditures are expected to fund the
development of additional gathering and processing capacity in
areas in which producers have increased drilling activity.

TRC
Assumptions

General and Administrative Expense. We have
assumed one quarter of the $5.4 million of the general and
administrative expense estimated for the twelve months ending
December 31, 2011.

Interest Expense. We assume that our Holdco
loan will have an average balance of approximately
$85 million for the three months ending December 31,
2010. Pursuant to the terms of such loan, we can pay interest
either in cash or in kind (PIK). We have assumed the cash pay
option of LIBOR plus a margin of 3%.

Interest Income. We estimate that we will
invest in a combination of cash and cash equivalents, treasuries
and liquid, investment grade securities. For the three months
ending December 31, 2010 we estimate such investments will
earn an average return of 2%.

Cash Taxes. We estimate that we will pay
approximately $3.2 million in taxes for the three months
ending December 31, 2010. This amount consists of
$3.7 million of tax liabilities, resulting from deferred
gains for previous drop down transactions, partially offset by
taxable losses that reduce taxes by $0.5 million. The
$3.2 million of cash taxes due will be funded from our cash
reserve.

Cash Reserve. We estimate that at the closing
of this offering we will have approximately $151 million of
cash on hand which will be sufficient to pay $3.2 million
of taxes for the three months ending December 31, 2010.

The following table presents selected historical consolidated
financial and operating data of Targa Resources Corp. for the
periods and as of the dates indicated. The selected historical
consolidated statement of operations and cash flow data for the
years ended December 31, 2007, 2008 and 2009 and selected
historical consolidated balance sheet data as of
December 31, 2009 and 2008 have been derived from our
audited financial statements, included elsewhere in this
prospectus. The selected historical consolidated statement of
operations and cash flow data for the nine months ended
September 30, 2009 and 2010 and the selected historical
consolidated balance sheet data as of September 30, 2010
have been derived from our unaudited financial statements,
included elsewhere in this prospectus.

The selected historical consolidated statement of operations and
cash flow data for the years ended December 31, 2005 and
2006 and the selected historical consolidated balance sheet data
as of December 31, 2005, 2006 and 2007 have been derived
from our audited financial statements, which are not included in
this prospectus. The selected historical consolidated balance
sheet data as of September 30, 2009 has been derived from
our unaudited financial statements, which are not included in
this prospectus.

We derived the information in the following table from, and that
information should be read together with and is qualified in its
entirety by reference to, the historical consolidated financial
statements and the accompanying notes beginning on
page F-1.

Includes business interruption
insurance proceeds of $3.0 million and $7.9 million
for the nine months ended September 30, 2010 and 2009 and
$21.5 million, $32.9 million, $7.3 million and
$10.7 million for the years ended December 31, 2009,
2008, 2007 and 2006.

(2)

Based on the terms of the preferred
convertible stock, undistributed earnings of the Company are
allocated to the preferred stock until the carrying value has
been recovered.

(3)

Gross margin is a non-GAAP
financial measure and is discussed under Managements
Discussion and Analysis of Financial Condition and Results of
OperationsHow We Evaluate Our Operations.

(4)

Operating margin is a non-GAAP
financial measure and is discussed under Managements
Discussion and Analysis of Financial Condition and Results of
OperationsHow We Evaluate Our Operations.

(5)

Plant natural gas inlet represents
the volume of natural gas passing through the meter located at
the inlet of a natural gas processing plant.

You should read the following discussion of our financial
condition and results of operations in conjunction with the
historical and pro forma consolidated financial statements and
notes thereto included elsewhere in this prospectus. For more
detailed information regarding the basis of presentation for the
following information, you should read the notes to the
historical and pro forma financial statements included elsewhere
in this prospectus. In addition, you should read
Forward-Looking Statements and Risk
Factors for information regarding certain risks inherent
in our and the Partnerships business.

Overview

Financial
Presentation

Because we control the General Partner, we reflect our ownership
interest in the Partnership on a consolidated basis, which means
that our financial results are combined with the
Partnerships financial results in our consolidated
financial statements. The limited partner interests in the
Partnership not owned by controlled affiliates of us are
reflected in our results of operations as net income
attributable to non-controlling interests. We currently have no
separate operating activities apart from those conducted by the
Partnership, and our cash inflows consist of cash distributions
from our interests in the Partnership. Throughout this
discussion, when we refer to our financial results
or our operations, we are referring to the financial results and
operations of all of our consolidated subsidiaries, including
the Partnership. Our consolidated financial statements differ
from the results of operations of the Partnership due to
non-controlling interests in the Partnership, and the effects of
certain assets, liabilities and insurance recoveries that were
retained by us and not included in our asset conveyances with
the Partnership. The historical results of operations do not
reflect incremental general and administrative expenses of
$1.0 million that we expect to incur as a result of being a
public company.

General

We are the sole member of Targa Resources GP LLC, which is the
general partner of the Partnership. Through our control of the
Partnership, we are a leading provider of midstream natural gas
and NGL services in the United States. We are engaged in the
business of gathering, compressing, treating, processing and
selling natural gas and storing, fractionating, treating,
transporting and selling NGLs and NGL products. We operate
through two divisions: the Natural Gas Gathering and Processing
division and the NGL Logistics and Marketing division. Our
interests in the Partnership consist of the following:



a 2% general partner interest, which we hold through our 100%
ownership interest in the general partner of the Partnership;



all Incentive Distribution Rights (IDRs); and



11,645,659 of the 75,545,409 outstanding common units of the
Partnership, representing a 15.1% limited partnership interest
in the Partnership.

Our cash flows are generated from the cash distributions we
receive from the Partnership. The Partnership is required to
distribute all available cash at the end of each quarter after
establishing reserves to provide for the proper conduct of its
business or to provide for future distributions.

Cash
Distributions

The following table sets forth the distributions that the
Partnership has paid in respect of the 2% general partner
interest, the associated IDRs and actual common units held
during the periods indicated. We will not distribute all of the
cash that we receive from the Partnership to our shareholders,
as we will

establish reserves for capital contributions, debt service
requirements, general, administrative and other expenses, future
distributions and other miscellaneous uses of cash.

Actual Cash Distributions

Cash

Limited

Distributions

Distributions

Distributions

Distribution

Partner

Total Partnership

on Limited

on General

to Targa

Per Limited

Units

Cash

Partner

Partner

Distributions

Resources

Partner Unit

Outstanding

Distributions

Units

Interest

on IDRs

Corp.

(In millions except and Cash Distribution Per Limited Partner
Unit)

2007

First Quarter

$

0.16875

30.9

$

5.3

$

5.2

$

0.1

$



$

2.1

Second Quarter

0.33750

30.9

10.6

10.4

0.2



4.1

Third Quarter

0.33750

44.4

15.3

15.0

0.3



4.2

Fourth Quarter

0.39750

46.2

18.9

18.4

0.4

0.1

5.1

2008

First Quarter

$

0.41750

46.2

$

19.9

$

19.3

$

0.4

$

0.2

$

5.5

Second Quarter

0.51250

46.2

25.9

23.7

0.5

1.7

8.2

Third Quarter

0.51750

46.2

26.3

23.9

0.5

1.9

8.4

Fourth Quarter

0.51750

46.2

26.4

24.0

0.5

1.9

8.4

2009

First Quarter

$

0.51750

46.2

$

26.3

$

23.9

$

0.5

$

1.9

$

8.4

Second Quarter

0.51750

46.2

26.4

23.9

0.5

2.0

8.5

Third Quarter

0.51750

61.6

35.2

31.9

0.7

2.6

13.7

Fourth Quarter

0.51750

68.0

38.8

35.2

0.8

2.8

14.0

2010

First Quarter

$

0.51750

68.0

$

38.8

$

35.2

$

0.8

$

2.8

$

9.6

Second Quarter

0.52750

68.0

40.2

35.9

0.8

3.5

10.4

Third Quarter

0.53750

75.5

46.1

40.6

0.9

4.6

11.8

Recent
Transactions

On July 19, 2010, the Partnership entered into an amended
and restated five-year $1.1 billion senior secured
revolving credit facility, which allows it to request increases
in commitments up to an additional $300 million. The
amended and restated senior secured credit facility replaces the
Partnerships former $977.5 million senior secured
revolving credit facility due February 2012.

In August 2010, the Partnership completed a public offering of
7,475,000 common units and a separate private offering of
$250,000,000 of
77/8% Senior
Notes due 2018. The Partnership used the net proceeds from these
offerings to reduce borrowings under its senior secured credit
facility.

On August 25, 2010, the Partnership acquired from us a 63%
ownership interest in Versado, a joint venture in which Chevron
U.S.A. Inc. owns the remaining 37% interest, for a purchase
price of $247.2 million. Versado owns a natural gas
gathering and processing business consisting of the Eunice,
Monument and Saunders gathering and processing systems,
including treating operations, processing plants and related
assets. The Versado System includes three refrigerated cryogenic
processing plants and approximately 3,200 miles of combined
gathering pipelines in Southeast New Mexico and West Texas and
is primarily conducted under percent of proceeds arrangements.
During 2009, the Versado System processed an average of
approximately
198.8 MMcf/d
of natural gas and produced an average of approximately
22.2 MBbl/d of NGLs. In the first nine months of 2010, the
Versado System processed an average of approximately
180.5 MMcf/d
of natural gas and produced an average of approximately
20.4 MBbl/d of NGLs.

On September 28, 2010, the Partnership acquired from us an
approximate 77% ownership interest in Venice Energy Services
Company, L.L.C. (VESCO), a joint venture in which
Enterprise Gas Processing, LLC and Oneok Vesco Holdings, L.L.C.
own the remaining ownership interests, for a purchase price of
$175.6 million. VESCO owns and operates a natural gas
gathering and processing business in Louisiana

consisting of a coastal straddle plant and the business and
operations of Venice Gathering System, L.L.C., a wholly owned
subsidiary of VESCO that owns and operates an offshore gathering
system and related assets (collectively, the VESCO
System). The VESCO System captures volumes from the Gulf
of Mexico shelf and deepwater. For the year ended
December 31, 2009 and for the nine months ended
September 30, 2010, VESCO processed
363 MMcf/d
and
423 MMcf/d
of natural gas, respectively.

On October 8, 2010, the Partnership declared a quarterly
cash distribution of $0.5375 per common unit, or $2.15 per
common unit on an annualized basis, for the third quarter of
2010, payable on November 12, 2010 to holders of record on
October 18, 2010.

On November 4, 2010, the Partnership announced that
management plans to recommend to the General Partners
board of directors a $0.04 increase in the annualized cash
distribution rate to $2.19 per common unit for the fourth
quarter of 2010 distribution.

Factors That
Significantly Affect Our Results

Upon completion of this offering, our only cash-generating
assets will consist of our interests in the Partnership.
Therefore, our cash flow and resulting ability to pay dividends
will be dependent upon the Partnerships ability to make
distributions in respect of those interests. The actual amount
of cash that the Partnership will have available for
distribution will depend primarily on the amount of cash it
generates from operations.

Our results of operations are substantially impacted by the
volumes that move through both our gathering and processing and
our logistics assets, our contract terms and changes in
commodity prices.

Volumes. In our gathering and processing
operations, plant inlet volumes and capacity utilization rates
generally are driven by wellhead production, our competitive
position on a regional basis and more broadly by the impact of
prices for oil, natural gas and NGLs on exploration and
production activity in the areas of our operation. The factors
that impact the gathering and processing volumes also impact the
total volumes that flow to our Downstream Business. In addition,
fractionation volumes are also affected by the location of the
resulting mixed NGLs, available pipeline capacity to transport
NGLs to our fractionators, and our competitive position relative
to other fractionators.

Contract Terms and Contract Mix and the Impact of Commodity
Prices. Our natural gas gathering and processing
contract arrangements can have a significant impact on our
profitability. Because of the significant volatility of natural
gas and NGL prices, the contract mix of our natural gas
gathering and processing segment can have a significant impact
on our profitability. Negotiated contract terms are based upon a
variety of factors, including natural gas quality, geographic
location, the competitive environment at the time the contract
is executed and customer preferences. Contract mix and,
accordingly, exposure to natural gas and NGL prices may change
over time as a result of changes in these underlying factors.

Set forth below is a table summarizing the contract mix of our
natural gas gathering and processing division for 2009 and the
potential impacts of commodity prices on operating margins:

Percent of

Contract Type

Throughput

Impact of Commodity Prices

Percent-of-Proceeds
/
Percent-of-Liquids

48

%

Decreases in natural gas and or NGL prices generate decreases in
operating margins

In periods of favorable processing
economics,(1)
similar to percent-of-liquids or to wellhead
purchases/keep-whole in some circumstances, if economically
advantageous to the processor. In periods of unfavorable
processing economics, similar to fee-based.

Favorable processing economics
typically occur when processed NGLs can be sold, after allowing
for processing costs, at a higher value than natural gas on a
Btu equivalent basis.

Actual contract terms are based upon a variety of factors,
including natural gas quality, geographic location, the
competitive commodity and pricing environment at the time the
contract is executed, and customer requirements. Our gathering
and processing contract mix and, accordingly, our exposure to
natural gas and NGL prices, may change as a result of producer
preferences, competition, and changes in production as wells
decline at different rates or are added, our expansion into
regions where different types of contracts are more common as
well as other market factors. We prefer to enter into contracts
with less commodity price sensitivity including fee-based and
percent-of-proceeds
arrangements.

The contract terms and contract mix of our downstream business
have a significant impact on our results of operations. During
periods of low relative demand for available fractionation
capacity, rates were low and take or pay contracts were not
readily available. Currently, demand for fractionation services
is relatively high, rates have increased, contract terms or
lengths have increased and reservation fees are required. These
fractionation contracts in the logistics assets segment are
primarily fee-based arrangements while the marketing segment
includes both fee based and percent of proceeds contracts.

We attempt to mitigate the impact of commodity prices on our
results of operations through hedging activities which can
materially impact our results of operations. See
Quantitative and Qualitative Disclosures About
Market Risk  Commodity Price Risk. Because the
Downstream Business is primarily fee based, our hedging
activities are primarily focused on the equity volume positions
associated with our percent-of-proceeds or percent-of-liquids
gas processing contracts.

Impact of Our Hedging Activities. In an effort
to reduce the variability of our cash flows, we have hedged the
commodity price associated with a portion of our expected
natural gas, NGL and condensate equity volumes for the remainder
of 2010 through 2013 by entering into derivative financial
instruments including swaps and purchased puts (or floors). With
these arrangements, we have attempted to mitigate our exposure
to commodity price movements with respect to our forecasted
volumes for this period. For additional information regarding
our hedging activities, see Quantitative and
Qualitative Disclosures About Market Risk  Commodity
Price Risk.

General Trends
and Outlook

We expect our business to continue to be affected by the
following key trends. Our expectations are based on assumptions
made by us and information currently available to us. To the
extent our underlying assumptions about or interpretations of
available information prove to be incorrect, our actual results
may vary materially from our expected results.

Demand for Our Services. Fluctuations in
energy prices can affect production rates and investments by
third parties in the development of oil and natural gas
reserves. Generally, drilling and production activity will
increase as energy prices increase. Although recent economic
conditions negatively impacted overall commodity prices, we
believe that the current strength of oil, condensate and NGL
prices compared to natural gas prices has caused producers in
and around our natural gas gathering and processing areas of
operation to focus their drilling programs on regions rich in
these forms of hydrocarbons. This focus is reflected in
increased drilling permits and higher rig counts in these areas,
and we expect these activities to lead to higher inlet volumes
over the next several years. Producer activity in areas rich in
oil, condensate and NGLs is currently generating increased
demand for our fractionation services and for related fee-based
services provided by our downstream business. While we expect
development activity to remain robust with respect to oil and
liquids rich gas development and production, currently depressed
natural gas prices have resulted in reduced activity levels
surrounding comparatively dry natural gas reserves, whether
conventional or unconventional.

No other third party customer accounted for more than 10% of our
consolidated revenues or consolidated product purchases during
these periods.

Commodity Prices. Current forward commodity
prices for the November 2010 through October 2011 period show
natural gas and crude oil prices strengthening while NGL prices
weaken on an absolute price basis and as a percentage of crude
oil. Various industry commodity price forecasts based on
fundamental analysis may differ significantly from forward
market prices. Both are subject to change due to multiple
factors. There has been and we believe there will continue to be
significant volatility in commodity prices and in the
relationships among NGL, crude oil and natural gas prices. In
addition, the volatility and uncertainty of natural gas, crude
oil and NGL prices impact drilling, completion and other
investment decisions by producers and ultimately supply to our
systems.

Our operating income generally improves in an environment of
higher natural gas, NGL and condensate prices, primarily as a
result of our
percent-of-proceeds
contracts. Our processing profitability is largely dependent
upon pricing, the supply of and market demand for natural gas,
NGLs and condensate, which are beyond our control and have been
volatile. Recent weak economic conditions have negatively
affected the pricing and market demand for natural gas, NGLs and
condensate, which caused a reduction in profitability of our
processing operations. In a declining commodity price
environment, without taking into account our hedges, we will
realize a reduction in cash flows under our
percent-of-proceeds
contracts proportionate to average price declines. We have
attempted to mitigate our exposure to commodity price movements
by entering into hedging arrangements. For additional
information regarding our hedging activities, see
Quantitative and Qualitative Disclosures about Market
RiskCommodity Price Risk.

Volatile Capital Markets. We are dependent on
our ability to access the equity and debt capital markets in
order to fund acquisitions and expansion expenditures. Global
financial markets have been, and are expected to continue to be,
volatile and disrupted and weak economic conditions may cause a
significant decline in commodity prices. As a result, we may be
unable to raise equity or debt capital on satisfactory terms, or
at all, which may negatively impact the timing and extent to
which we execute growth plans. Prolonged periods of low
commodity prices or volatile capital markets may impact our
ability or willingness to enter into new hedges, fund organic
growth, connect to new supplies of natural gas, execute
acquisitions or implement expansion capital expenditures.

Increased Regulation. Additional regulation in
various areas has the potential to materially impact our
operations and financial condition. For example, if regulation
of hydraulic fracturing used by producers increased, we may
experience reductions in supplies of natural gas and of NGLs
from producers. Please read Risk FactorsIncreased
regulation of hydraulic fracturing could result in reductions or
delays in drilling and completing new oil and natural gas wells,
which could adversely impact the Partnerships revenues by
decreasing the volumes of natural gas that the Partnership
gathers, processes and fractionates. Similarly, the
forthcoming rules and regulations of the CFTC may limit our
ability or increase the cost to use derivatives, which could
create more volatility and less predictability in our results of
operations. Please read Risk FactorsThe recent
adoption of derivatives legislation by the United States
Congress could have an adverse effect on the Partnerships
ability to hedge risks associated with its business.

How We Evaluate
Our Operations

Our profitability is a function of the difference between the
revenues we receive from our operations, including revenues from
the natural gas, NGLs and condensate we sell, and the costs

associated with conducting our operations, including the costs
of wellhead natural gas and mixed NGLs that we purchase as well
as operating and general and administrative costs. Because
commodity price movements tend to impact both revenues and
costs, increases or decreases in our revenues alone are not
necessarily indicative of increases or decreases in our
profitability. Our contract portfolio, the prevailing pricing
environment for natural gas and NGLs, and the volumes of natural
gas and NGL throughput on our systems are important factors in
determining our profitability. Our profitability is also
affected by the NGL content in gathered wellhead natural gas,
supply and demand for our products and services provided to and
changes in our customer mix.

Throughput Volumes, Facility Efficiencies and Fuel
Consumption. Our profitability is impacted by our
ability to add new sources of natural gas supply to offset the
natural decline of existing volumes from natural gas wells that
are connected to our gathering and processing systems. This is
achieved by connecting new wells and adding new volumes in
existing areas of production as well as by capturing natural gas
supplies currently gathered by third parties. Similarly, our
profitability is impacted by our ability to add new sources of
mixed NGL supply, typically connected by third party
transportation, to our downstream fractionation facilities. We
fractionate NGLs generated by our gathering and processing
plants as well as by contracting for mixed NGL supply from third
party gathering or fractionation facilities.

In addition, we seek to increase operating margins by limiting
volume losses and reducing fuel consumption by increasing
compression efficiency. With our gathering systems
extensive use of remote monitoring capabilities, we monitor the
volumes of natural gas received at the wellhead or central
delivery points along our gathering systems, the volume of
natural gas received at our processing plant inlets and the
volumes of NGLs and residue natural gas recovered by our
processing plants. We also monitor the volumes of NGLs received,
stored, fractionated, and delivered across our logistics assets.
This information is tracked through our processing plants and
downstream facilities to determine customer settlements for
sales and volume related fees for service and helps us increase
efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we
measure the difference between the volume of natural gas
received at the wellhead or central delivery points on our
gathering systems and the volume received at the inlet of our
processing plants as an indicator of fuel consumption and line
loss. We also track the difference between the volume of natural
gas received at the inlet of the processing plant and the NGLs
and residue gas produced at the outlet of such plant to monitor
the fuel consumption and recoveries of the facilities. Similar
tracking is performed for our logistics assets. These volume,
recovery and fuel consumption measurements are an important part
of our operational efficiency analysis.

Operating Expenses. Operating expenses are
costs associated with the operation of a specific asset. Direct
labor, ad valorem taxes, repair and maintenance, utilities and
contract services comprise the most significant portion of our
operating expenses. These expenses generally remain relatively
stable independent of the volumes through our systems but
fluctuate depending on the scope of the activities performed
during a specific period.

Gross Margin. With respect to our Natural Gas
Gathering and Processing division, we define gross margin as
total operating revenues, which consist of natural gas and NGL
sales plus service fee revenues, less product purchases, which
consist primarily of producer payments and other natural gas
purchases. With respect to our Logistics Assets segment, we
define gross margin as total revenue, which consists primarily
of service fee revenue. With respect to our Marketing and
Distribution segment, we define gross margin as total revenue,
which consists primarily of service fee revenues and NGL sales,
less cost of sales, which consists primarily of NGL purchases
and changes in inventory valuation.

Operating Margin. We review performance based
on operating margin. We define operating margin as revenues,
which consist of natural gas and NGL sales plus service fee
revenues, less product

purchases, which consist primarily of producer payments and
other natural gas purchases, and operating expenses. Natural gas
and NGL sales revenue includes settlement gains and losses on
commodity hedges. Our operating margin is impacted by volumes
and commodity prices as well as by our contract mix and hedging
program, which are described in more detail below. We view our
operating margin as an important performance measure of the core
profitability of our operations. We review our operating margin
monthly for consistency and trend analysis.

The GAAP measure most directly comparable to gross margin and
operating margin is net income. Gross margin and operating
margin should not be considered as an alternative to GAAP net
income. Gross margin and operating margin are not presentations
made in accordance with GAAP and have important limitations as
an analytical tool. You should not consider gross margin and
operating margin in isolation or as a substitute for analysis of
our results as reported under GAAP. Because gross margin and
operating margin exclude some, but not all, items that affect
net income and are defined differently by different companies in
our industry, our definition of gross margin and operating
margin may not be comparable to similarly titled measures of
other companies, thereby diminishing their utility.

We compensate for the limitations of gross margin and operating
margin as an analytical tool by reviewing the comparable GAAP
measure, understanding the differences between the measures and
incorporating these insights into our decision-making processes.

Nine Months

Year Ended December 31,

Ended September 30,

2005

2006

2007

2008

2009

2009

2010

(In millions)

Reconciliation of gross margin and operating margin to net
income attributable to Targa Resources Corp.:

Gross margin

$

197.0

$

692.1

$

771.7

$

780.4

$

744.9

$

520.1

$

554.4

Operating (expenses)

(53.4

)

(222.8

)

(247.1

)

(275.2

)

(235.0

)

(182.7

)

(190.4

)

Operating margin

143.6

469.3

524.6

505.2

509.9

337.4

364.0

Net income attributable to noncontrolling interest

(7.3

)

(26.0

)

(48.1

)

(97.1

)

(49.8

)

(17.7

)

(46.2

)

Depreciation and amortization expenses

(27.1

)

(149.7

)

(148.1

)

(160.9

)

(170.3

)

(127.9

)

(136.9

)

General and administrative expenses

(29.1

)

(82.5

)

(96.3

)

(96.4

)

(120.4

)

(83.6

)

(81.0

)

Interest expense, net

(39.8

)

(180.2

)

(162.3

)

(141.2

)

(132.1

)

(102.8

)

(83.9

)

Gain (loss) on debt repurchase







25.6

(1.5

)

(1.5

)

(17.4

)

Gain (loss) on early debt extinguishment

(3.3

)





3.6

9.7

10.4

8.1

Income tax (expense) benefit

7.0

(16.7

)

(23.9

)

(19.3

)

(20.7

)

(5.1

)

(18.5

)

Other, net

(59.8

)

10.0

10.2

17.8

4.5

3.8

4.6

Net income (loss) attributable to Targa Resources Corp.

$

(15.8

)

$

24.2

$

56.1

$

37.3

$

29.3

$

13.0

$

(7.2

)

We believe that investors benefit from having access to the same
financial measures that our management uses in evaluating our
operating results. Operating margin provides useful information
to investors because it is used as a supplemental financial
measure by us and by external users of our financial statements,
including such investors, commercial banks and others, to assess: